For further information:
Michele Lopiccolo, VP, Investor Relations
Phone 504/576-4879, Fax 504/576-2897
mlopicc@entergy.com

INVESTOR NEWS

Exhibit 99.1

May 4, 2009

ENTERGY REPORTS FIRST QUARTER EARNINGS

NEW ORLEANS - Entergy Corporation reported first quarter 2009 earnings of $1.20 per share on an as-reported basis and $1.29 per share on an operational basis, as shown in Table 1 below. A more detailed discussion of quarterly results begins on page 2 of this release.

Table 1: Consolidated Earnings - Reconciliation of GAAP to Non-GAAP Measures
First Quarter 2009 vs. 2008
(Per share in U.S. $)
	2009	2008	Change
As-Reported Earnings	1.20	1.56	(0.36)
Less Special Items	(0.09)	-	(0.09)
Operational Earnings	1.29	1.56	(0.27)
Weather Impact	(0.02)	(0.03)	0.01

Operational Earnings Highlights for First Quarter 2009

• Utility, Parent & Other results were lower due to higher other taxes and depreciation and amortization expenses.
• Entergy Nuclear earnings decreased as a result of lower production due to additional planned refueling outage days and impairments recorded on decommissioning trust fund investments.
• Entergy's Non-Nuclear Wholesale Assets results were essentially flat.

"In the current uncertain climate, we have focused significant effort on positioning the company for long-term success while weathering the current economic storm," said J. Wayne Leonard, Entergy's chairman and chief executive officer. "While we cannot predict what will come next in these times, we will be relentless in seeking value and managing risk, and we are prepared to seize opportunities that add value for our stakeholders."

Table of Contents                                                   Page
I.	Consolidated Results	2
II.	Utility, Parent & Other Results	3
III.	Competitive Businesses Results	4
IV.	Other Financial Performance Highlights	5
V.	Business Separation	8
VI.	Appendices
	A. Spin-Off of Non-Utility Nuclear Business	9
	B. Variance Analysis and Special Items	12
	C. Regulatory Summary	13
	D. Financial Performance Measures and        Historical Performance Measures	18
	E. Planned Capital Expenditures	20
	F. Definitions	21
	G. GAAP to Non-GAAP Reconciliations	23
VII.	Financial Statements	26

Entergy's business highlights include the following:

• Leonard was named one of the nation's "Best CEOs" by Institutional Investor magazine, his sixth consecutive year for achieving the honor.
• Entergy received its 12th and 13th industry awards for restoring power after major storms and is the only company recognized 11 years in a row by Edison Electric Institute for its storm restoration work.
• Indian Point 3 completed 678 continuous days of operation as it entered its refueling outage in March. This run marked an operating record for Westinghouse Pressurized Water Reactors which account for nearly one-fourth of the commercial nuclear power reactors in the U.S.

Entergy will host a teleconference to discuss this release at 10 a.m. CDT on Monday, May 4, 2009, with access by telephone, 719-457-2080, confirmation code 8064872. The call and presentation slides can also be accessed via Entergy's Web site at www.entergy.com. A replay of the teleconference will be available for seven days thereafter by dialing 719-457-0820, confirmation code 8064872. The replay will also be available on Entergy's Web site at www.entergy.com.

I. Consolidated Results

Consolidated Earnings

Table 2 provides a comparative summary of consolidated earnings per share for first quarter 2009 versus 2008, including a reconciliation of GAAP as-reported earnings to non-GAAP operational earnings. Utility, Parent & Other had lower earnings due to higher other taxes and depreciation and amortization expenses. Entergy Nuclear's earnings decreased as a result of lower revenue due to lower production resulting from additional planned refueling outage days and impairments on decommissioning trust fund investments. Entergy's Non-Nuclear Wholesale Assets business reported results essentially equal to those of first quarter 2008.

Table 2: Consolidated Earnings - Reconciliation of GAAP to Non-GAAP Measures First Quarter 2009 vs. 2008 (see appendix F for definitions of certain measures)
(Per share in U.S. $)
	First Quarter
	2009	2008	Change
As-Reported
Utility, Parent & Other	0.32	0.48	(0.16)
Entergy Nuclear	0.91	1.12	(0.21)
Non-Nuclear Wholesale Assets	(0.03)	(0.04)	0.01
Consolidated As-Reported Earnings	1.20	1.56	(0.36)
Less Special Items
Utility, Parent & Other	(0.05)	-	(0.05)
Entergy Nuclear	(0.04)	-	(0.04)
Non-Nuclear Wholesale Assets	-	-	-
Consolidated Special Items	(0.09)	-	(0.09)
Operational
Utility, Parent & Other	0.37	0.48	(0.11)
Entergy Nuclear	0.95	1.12	(0.17)
Non-Nuclear Wholesale Assets	(0.03)	(0.04)	0.01
Consolidated Operational Earnings	1.29	1.56	(0.27)
Weather Impact	(0.02)	(0.03)	0.01

Detailed earnings variance analysis is included in appendix B-1 to this release. In addition, appendix B-2 provides details of special items shown in Table 2 above.

Consolidated Net Cash Flow Provided by Operating Activities

Entergy's net cash flow provided by operating activities in first quarter 2009 was $375 million compared to $448 million in first quarter 2008. The decrease was due primarily to:

• net effect of hurricanes Gustav and Ike and a major Arkansas ice storm which reduced operating cash flow at the Utility by $314 million as a result of costs associated with system repairs
• higher working capital requirements of $113 million at Utility
• higher expenses associated with non-utility nuclear spin-off costs and dis-synergies totaling $23 million

Offsets include:

• an increased deferred fuel contribution at the Utility in the current quarter totaling $471 million

Table 3 provides the components of net cash flow provided by operating activities contributed by each business with quarter-to-quarter comparisons.

Table 3: Consolidated Net Cash Flow Provided by Operating Activities
First Quarter 2009 vs. 2008
(U.S. $ in millions)
	First Quarter
	2009	2008	Change
Utility, Parent & Other	127	123	4
Entergy Nuclear	254	340	(86)
Non-Nuclear Wholesale Assets	(6)	(15)	9
Total Net Cash Flow Provided by Operating Activities	375	448	(73)

II. Utility, Parent & Other Results

In first quarter 2009, Utility, Parent & Other had earnings of $0.32 per share on an as-reported basis and $0.37 per share on an operational basis, compared to earnings of $0.48 per share on as-reported and operational bases in first quarter 2008. Operational results for Utility, Parent & Other in first quarter 2009 reflect higher taxes other than income taxes due to the absence of the benefit associated with favorable resolution of tax audit issues that was included in results in first quarter 2008. Higher depreciation and amortization expense also contributed to lower results in the current quarter.

Electricity usage, in gigawatt-hour sales by customer segment, is included in Table 4. Current quarter sales reflect the following:

• Residential sales in first quarter 2009, on a weather-adjusted basis, showed a 1.8 percent decrease compared to first quarter 2008, which was also a leap-year.
• Commercial and governmental sales, on a weather-adjusted basis, decreased 1.2 percent year over year.
• Industrial sales in the first quarter were down 13.2 percent compared to the same quarter of 2008.

The residential and commercial and governmental sales sectors reflected a decrease quarter to quarter as the continued weakening in the economy affected customer usage across these sectors. Sales in the industrial sector for first quarter 2009 decreased significantly compared to the same quarter of 2008 primarily due to a weak economic climate that worsened in the current period. Small and mid-sized industrial customers are also being negatively affected by overseas competition. Despite the lower sales volume, net revenue at the Utility was essentially flat, in part due to the fact that a significant portion of the industrial customer bill is based on a fixed charge basis that does not vary linearly with volume changes.

Table 4 provides a comparative summary of the Utility's operational performance measures.

Table 4: Utility Operational Performance Measures
First Quarter 2009 vs. 2008 (see appendix F for definitions of measures)
	First Quarter
	2009	2008	% Change	% Weather Adjusted
GWh billed
Residential	7,893	8,011	-1.5%	-1.8%
Commercial and governmental	6,756	6,807	-0.7%	-1.2%
Industrial	8,139	9,377	-13.2%	-13.2%
Total Retail Sales	22,788	24,195	-5.8%	-6.0%
Wholesale	1,387	1,290	7.5%
Total Sales	24,175	25,485	-5.1%
O&M expense	$18.51	$17.26	7.2%
Number of retail customers
Residential	2,321,488	2,297,765	1.0%
Commercial and governmental	343,871	341,066	0.8%
Industrial	38,892	40,860	-4.8%

Appendix C provides information on selected pending local and federal regulatory cases.

III. Competitive Businesses Results

Entergy's competitive businesses include Entergy Nuclear and Non-Nuclear Wholesale Assets.

Entergy Nuclear

Entergy Nuclear earned $0.91 per share on an as-reported basis and $0.95 per share on an operational basis in first quarter 2009, compared to $1.12 per share on as-reported and operational bases in first quarter 2008. Entergy Nuclear's earnings decreased primarily as a result of lower revenue due to lower generation resulting from additional planned refueling outage days and lower revenue amortization for the Palisades below-market Power Purchase Agreement. Impairments recorded in the current period associated with decommissioning trust fund investments also contributed to lower earnings.

Table 5 provides a comparative summary of Entergy Nuclear's operational performance measures.

Table 5: Entergy Nuclear Operational Performance Measures
First Quarter 2009 vs. 2008 (see appendix F for definitions of measures)
	First Quarter
	2009	2008	% Change
Net MW in operation	4,998	4,998	-
Average realized price per MWh	$63.84	$61.47	4%
Production cost per MWh	$23.14	$19.98	16%
Non-fuel O&M expense/purchased power per MWh	$22.44	$20.20	11%
GWh billed	10,074	10,760	-6%
Capacity factor	92%	97%	-5%
Refueling outage days:
Indian Point 2	-	7
Indian Point 3	21	-
Palisades	9	-

Entergy Nuclear's sold forward position is 87 percent, 66 percent, and 46 percent of planned generation at average prices per megawatt-hour of $60, $60 and $56, for 2009, 2010, and 2011, respectively. Table 6 provides capacity and generation sold forward projections for Entergy Nuclear.

Table 6: Entergy Nuclear's Capacity and Generation Projected Sold Forward
2009 through 2013 (see appendix F for definitions of measures)
	Remainder of 2009	2010	2011	2012	2013
Energy
Planned TWh of generation	31	40	41	41	40
Percent of planned generation sold forward (a)
Unit-contingent	47%	31%	29%	18%	12%
Unit-contingent with availability guarantees	40%	35%	17%	7%	6%
Firm LD	0%	0%	0%	0%	0%
Total	87%	66%	46%	25%	18%
Average contract price per MWh (b)	$60	$60	$56	$54	$50
Capacity
Planned net MW in operation	4,998	4,998	4,998	4,998	4,998
Percent of capacity sold forward
Bundled capacity and energy contracts	26%	26%	25%	18%	16%
Capacity contracts	53%	34%	25%	10%	0%
Total	79%	60%	50%	28%	16%
Average capacity contract price per kW per month	$2.3	$3.4	$3.6	$3.6	-
Blended Capacity and Energy Recap (based on revenues)
Percent of planned energy and capacity sold forward	89%	68%	46%	22%	14%
Average contract revenue per MWh (b)	$62	$62	$59	$56	$50
(a) A portion of EN's total planned generation sold forward is associated with the Vermont Yankee contract for which pricing may be adjusted.
(b) Average contract prices exclude potential payments that may be owed under the value sharing agreement with the New York Power Authority.

Non-Nuclear Wholesale Assets

Entergy's Non-Nuclear Wholesale Assets business results were essentially unchanged in first quarter 2009 compared to first quarter 2008 with a loss of $(0.03) per share in the current period compared to $(0.04) per share a year ago.

IV. Other Financial Performance Highlights

Earnings Guidance

Entergy is reaffirming 2009 earnings guidance in the range of $6.70 to $7.30 per share on an operational basis, assuming a business as usual operation for the full year. As-reported guidance ranges from $6.56 to $7.16 and reflects $(0.14) per share of projected dis-synergies associated with the spin-off of Entergy's non-utility nuclear business and plans to enter into a nuclear services joint venture, both discussed below and in Appendix A. Guidance for 2009 does not include a special item for expenses, which were incurred beginning in 2008 and continuing in first quarter 2009, anticipated in connection with the outside services provided to pursue the spin-off. Entergy has indicated that should the current economic climate and power prices on Entergy Nuclear's open position persist for the balance of 2009, earnings could approach the lower end of the guidance ranges. Year-over-year changes are shown as point estimates and are applied to 2008 actual results to compute the 2009 guidance midpoint. Because there is a range of possible outcomes associated with each earnings driver, a range is applied to the calculated guidance midpoints to produce Entergy's guidance ranges for as-reported and operational earnings. 2009 earnings guidance is detailed in Table 7 below.

Table 7: 2009 Earnings Per Share Guidance - As Reported and Operational
(Per share in U.S. $) - Prepared January 2009
Segment	Description of Drivers	2008 Earnings Per Share	Expected Change	2009 Guidance Midpoint	2009 Guidance Range
Utility, Parent & Other	2008 Operational Earnings per Share	2.43
	Adjustment to normalize weather		0.02
	Increased net revenue due to sales growth and rate actions		0.45
	Decreased O&M expense		0.25
	Decreased income taxes		0.15
	Accretion/other		0.15
	Subtotal	2.43	1.02	3.45
Entergy Nuclear	2008 Operational Earnings per Share	4.07
	Increased net revenue due to higher pricing, lower volume		0.25
	Increased O&M/RFO expense		(0.05)
	Increased income taxes		(0.60)
	Accretion/other		(0.02)
	Subtotal	4.07	(0.42)	3.65
Non-Nuclear Wholesale Assets	2008 Operational Earnings per Share	0.01
	Increased losses		(0.11)
	Subtotal	0.01	(0.11)	(0.10)
Consolidated Operational	2008 Operational Earnings per Share	6.51	0.49	7.00	6.70 - 7.30
Consolidated	2008 As-Reported Earnings per Share	6.23
As-Reported	Changes detailed above		0.49
	2009 Non-Utility Nuclear spin-off dis-synergies		(0.14)
	2008 Non-Utility Nuclear spin-off expenses for outside services		0.28
	2009 As-Reported	6.23	0.63	6.86	6.56 - 7.16

Key assumptions supporting 2009 earnings guidance are as follows:

Utility, Parent & Other

• Normal weather
• Retail sales growth just under 3 percent, considering effects of 2008 hurricanes and industrial expansion; nearly flat on a normalized basis excluding hurricane effect and industrial expansion
• Increased revenue associated with rate actions
• Decreased non-fuel operation and maintenance expense, due to absence of Entergy Arkansas' 4^th quarter 2008 charge associated with non-recovery of storm reserve and removal costs; inflation essentially offset by cost reduction initiatives
• Decreased income taxes due to lower effective tax rate in 2009 compared to 2008
• Accretion/other is primarily driven by carrying costs recorded on unrecovered storm costs in 2009, and lower interest expense at the Parent due to lower debt outstanding and lower interest rate on corporate revolver, partially offset by higher depreciation expense associated with capital additions

Entergy Nuclear

• 41 TWh of total output, reflecting an approximate 93 percent capacity factor, including 30 day refueling outages at Pilgrim and Palisades and 38 days at Indian Point 3 in Spring 2009
• 86 percent of energy sold under existing contracts; 14 percent sold into the spot market
• $61/MWh average energy contract price; $58/MWh average unsold energy price based on published market prices at the end of 2008
• Palisades below-market PPA revenue amortization of $53 million in 2009, down from $76 million in 2008
• Non-fuel O&M/refueling outage expense growth of approximately 2 percent
• Increased income taxes due to higher effective tax rate in 2009 compared to 2008

Non-Nuclear Wholesale Assets

• Increased losses associated with a business that targets a break-even operation

Share Repurchase Program

• 2009 average fully diluted shares outstanding of approximately 194 million (including effect of equity units conversion)

Effective Income Tax Rate

• 2009 assumes an overall effective income tax rate of 37 percent

Earnings guidance for 2009 should be considered in association with earnings sensitivities as shown in Table 8. These sensitivities illustrate the estimated change in operational earnings resulting from changes in various revenue and expense drivers. Utility sales are expected to be the most significant variable for 2009 results for Utility, Parent & Other. At Entergy Nuclear, energy prices are expected to be the most significant driver of results in 2009. Estimated annual impacts shown in Table 8 are intended to be indicative rather than precise guidance.

Table 8: 2009 Earnings Sensitivities
(Per share in U.S. $)
Variable	2009 Guidance Assumption	Description of Change	Estimated Annual Impact (c)
Utility, Parent & Other
Sales growth   Residential   Commercial/Governmental   Industrial	Just under 3% total sales growth	1% change in Residential MWh sold 1% change in Comm/Govt MWh sold 1% change in Industrial MWh sold	- / + 0.05 - / + 0.04 - / + 0.02
Rate base	Growing rate base	$100 million change in rate base	- / + 0.03
Return on equity	See Appendix C	1% change in allowed ROE	- / + 0.33
Entergy Nuclear
Capacity factor	93% capacity factor	1% change in capacity factor	- / + 0.08
Energy price	14% energy unsold at $58/MWh in 2009	$10/MWh change for unsold energy	- / + 0.18
Non-fuel operation and maintenance expense	$23/MWh non-fuel operation and maintenance expense/purchased power	$1 change per MWh	- / + 0.13
Outage (lost revenue only)	93% capacity factor, including refueling outages for three northeast units	1,000 MW plant for 10 days at average portfolio energy price of $61/MWh for sold and $58/MWh for unsold volumes in 2009	- 0.04 / n/a
(c) Based on 2008 operational average fully diluted shares outstanding of approximately 196 million.

Liquidity

At the end of the first quarter, Entergy had $1.8 billion of cash and cash equivalents on hand on a consolidated basis. Entergy also has additional financing authority, subject to debt covenants, including undrawn revolving credit facility capacity of $725 million at the end of the first quarter. Entergy routinely tests the adequacy of its liquidity under various stress scenarios and believes its current liquidity position affords the desired level of financial flexibility. Entergy Corporation's revolving credit facility requires it to maintain a consolidated debt ratio of 65 percent or less of its total capitalization. Some of the utility company credit facilities also have similar covenants.

For 2009, Entergy projected consolidated net liquidity sources of approximately $2.9 billion taking into consideration its liquidity position at December 31, 2008 and other projected sources and uses of liquidity generated in 2009. Primary sources included projected undrawn revolving credit facility capacity, operating cash flow, and planned financing/refinancing activity, primarily for Entergy Texas and other Utility Operating Companies, as well as the refinancing of $500 million of Entergy Corporation Senior Notes. Uses focused on meeting debt maturities in the fourth quarter and other voluntary debt repayment (primarily pursuant to Entergy Texas Debt Assumption Agreement and for revolving credit facilities), equity units conversion of $500 million debt to equity, as well as capital expenditures, dividend payments and share repurchases.

During the first quarter, Entergy Texas successfully completed a $500 million financing in January. Entergy expects there will be similar windows of opportunity to access the credit markets in 2009. In addition, higher than projected storm expenditures for the January ice storm in Arkansas and hurricanes Gustav and Ike will result in lower operating cash flow. To the extent earnings approach the lower end of the guidance range, operating cash flow could be further reduced. Taking these factors into consideration, Entergy continues to see its net liquidity sources above $2 billion, affording the desired level of financial flexibility on a consolidated basis from a liquidity perspective.

Table 9 provides a summary of liquidity sources and uses from December 31, 2008 through December 31, 2009.

Table 9: Entergy Corporation Liquidity-Sources and Uses December 31, 2008 through December 31, 2009
(U.S. $ in billions) - Prepared January 2009	From 12/31/2008 through 12/31/2009 (d)
Cash and cash equivalents at December 31, 2008	1.9
Undrawn revolving credit facility capacity	2.6
Operating cash flow (e)	2.8
Planned financing/refinancing	2.0
Total liquidity sources	9.3
Debt maturities/voluntary repayment	(3.3)
Capital expenditures	(2.2)
Return of capital (dividends, net share repurchases)	(0.7)
Fuel purchases, decommissioning trust, other	(0.2)
Total liquidity uses	(6.4)
Net liquidity sources	2.9
(d) Sources and uses are reported on a business as usual basis and do not incorporate potential spin-off debt transactions.   (e) Assumes receipt of storm securitization proceeds for Entergy Texas and cash tax payments lower than statutory rate.

Debt Maturities

Debt maturities in 2009 include just over $500 million in the fourth quarter. In April, Entergy Arkansas entered into a new credit facility agreement through April 2010 in the amount of $88 million. Prior to expiration in May, Entergy Mississippi expects to renew its revolving credit facilities of $50 million. These facilities are generally renewed on an annual basis. The remaining credit facilities expire in 2012.

Table 10 provides details on Entergy's debt maturities.

Table 10: Entergy Corporation and Subsidiaries Debt Maturity Schedule (f)(g)
(U.S. $ in millions)
Maturities	4Q 2009	2010	2011	2012	2013+
Utility	219	457	280 (h)	236 (h)	5,546 (h)
Entergy Nuclear	22	31	31	30	96
Parent Company and    Other Business Segments	267	275	86	3,233	-
Total	508	763	397	3,499	5,642
(f) Long-term debt, including current portion, reported on a business as usual basis; does not incorporate potential spin-off debt transactions. (g) Excludes $180 million long-term DOE obligation and $508 million total lease obligations for Waterford 3 and Grand Gulf. (h) Pursuant to the jurisdictional separation of Entergy Gulf States, Entergy Texas has until December 31, 2010 to repay debt assumed under the      debt assumption agreement including $92 million otherwise due in 2011, $64 million in 2012 and $387 million due in 2013+.

V. Business Separation

On November 3, 2007, Entergy's Board of Directors approved a plan to pursue a separation of the non-utility nuclear business from Entergy's regulated utility business through a tax-free spin-off of the non-utility nuclear business. Enexus Energy Corporation will be a new, independent publicly traded company. In addition, Entergy and Enexus intend to enter into a nuclear services joint venture, with equal ownership. EquaGen LLC has been selected as the name for the joint venture.

Progress achieved since the last quarter update and/or current status include:

• An advisory committee of announced members of the Enexus Board has begun to meet periodically.
• Discussions continue with regulators in Vermont and New York
  • In Vermont, all scheduled procedural matters have been completed and a decision from the Vermont Public Service Board is pending.
  • In New York, settlement discussions are ongoing per the December 2008 notification by the ALJs that the parties intended to conduct a settlement discussion.
• Entergy and Enexus remain in a rolling readiness posture.

The state regulatory decisions and financing continue as the critical path items. The rolling readiness posture enables Entergy to execute the spin-off following receipt of regulatory approvals and once the timing is right to access the credit markets, both on acceptable terms.

Additional information on the spin-off including proposed new business structure, leadership teams, business overviews, financial aspirations, and a transaction timeline including regulatory filing status are included in Appendix A of this release.

VI. Appendices

Seven appendices are presented in this section as follows:

• Appendix A includes information on Entergy's plan to separate the non-utility nuclear business from Entergy's regulated utility business through a tax-free spin-off of the non-utility nuclear business.
• Appendix B includes earnings per share variance analysis and detail on special items that relate to the current quarter.
• Appendix C provides information on selected pending local and federal regulatory cases.
• Appendix D provides financial metrics for both current and historical periods. In addition, historical financial and operating performance metrics are included for the trailing eight quarters.
• Appendix E provides a summary of planned capital expenditures for the next three years.
• Appendix F provides definitions of the operational performance measures and GAAP and non-GAAP financial measures that are used in this release.
• Appendix G provides a reconciliation of GAAP to non-GAAP financial measures used in this release.

Appendix A provides information on Entergy's planned spin-off of its non-utility nuclear business.

Appendix A: Spin-off of Non-Utility Nuclear Business

The announced spin-off of Entergy's non-utility nuclear business will establish a new independent, publicly traded company. Enexus Energy Corporation has been selected as the name of the new company. In addition, Entergy and Enexus intend to enter into a nuclear services joint venture, with equal ownership. EquaGen LLC has been selected as the name for the joint venture. Below are transaction details and other information on Entergy, Enexus and EquaGen.

New Business Structure

Once the transaction is complete, Entergy Corporation's shareholders will own 100 percent of the common equity in both Entergy and Enexus. Enexus' business is expected to be comprised of the non-utility nuclear assets, including the Pilgrim Nuclear Station in Plymouth, Mass., the James A. FitzPatrick and Indian Point Energy Center plants in Oswego and Buchanan, N.Y., respectively, the Palisades plant in Covert, Mich., and the Vermont Yankee plant in Brattleboro, Vt., and a power marketing operation. Entergy's business will be comprised of the current six regulated utility operating subsidiaries, System Energy Resources, Inc., the related services subsidiaries System Fuels, Inc., Entergy Operations, Inc. and Entergy Services, Inc., and the remaining Entergy subsidiaries. The newly created joint venture, EquaGen, is expected to operate the nuclear assets owned by Enexus. EquaGen is also expected to offer nuclear services to third parties, including decommissioning, plant relicensing and plant operations for Cooper Nuclear Station and others.

The joint venture operating structure for Enexus ensures that the core nuclear operations expertise currently in place at each of the non-utility nuclear plants will remain after the spin-off. Entergy Nuclear Operations, Inc., the current NRC-licensed operator of the non-utility nuclear plants, is expected to be wholly-owned by EquaGen and will remain the operator of the plants after the separation. Entergy Operations, Inc., the current NRC-licensed operator of Entergy's utility nuclear plants, will also remain in place as a wholly-owned subsidiary of Entergy and will continue to be the operator of the utility nuclear plants. The decision to retain the existing operators for the nuclear stations reflects Entergy's commitment to maintaining safety, security and operational excellence.

Leadership Team

The Entergy Board of Directors has approved certain elements of the leadership structure and designated individuals who will fill key board and management roles. The EquaGen Board of Managers will be comprised of equal membership from both Entergy and Enexus.

Brief Overview of Each Business

After completion of the business separation, Entergy will consist of the current six electric utility subsidiaries in four contiguous states with generating capacity of more than 22,000 megawatts and 15,000 miles of transmission lines. Entergy will be a customer service-focused electric and gas utility with a unique growth opportunity through its portfolio transformation strategy that benefits customers. The company will deliver electricity to 2.7 million customers in Arkansas, Louisiana, Mississippi, and Texas and will remain headquartered in New Orleans, La.

Enexus is expected to own nearly 5,000 megawatts of nuclear generation, most of which is located in the northeastern United States. This location has some of the highest average regional power prices in the United States both today and expected into the future through at least 2020. The company will be headquartered in Jackson, Miss.

EquaGen is expected to be owned 50 percent each by Entergy and Enexus, and expected to have operating responsibility for Enexus' nuclear fleet. As a premier nuclear operator, the joint venture will have broad nuclear experience building and operating boiling and pressurized water reactor technologies. EquaGen is expected to be uniquely positioned to grow through offerings of nuclear operating expertise, as well as ancillary nuclear services to third parties, including plant decommissioning and relicensing. The company will be headquartered in Jackson, Miss.

Financial Aspirations

The companies will continue to aspire to deliver superior value to owners as measured by total shareholder return. The companies believe top-quartile shareholder returns are achieved by growing earnings, delivering returns at or above the risk-adjusted cost of capital, maintaining credit quality and flexibility, and deploying capital in a disciplined manner, whether for new investments, share repurchases, dividends or debt retirements.

Financial aspirations through 2012 include the following:

Top-quartile total shareholder return:

• Entergy: 6-8% annual earnings per share growth, a 70 to 75% dividend payout ratio target, and capacity for a new share repurchase program targeted at $2.5 billion, $0.5 billion of which has already been authorized by the Entergy Board of Directors, with the balance to be authorized and to commence following completion of spin-off

• Enexus: $2 billion in earnings before interest, income taxes, depreciation and amortization and interest and dividend income (EBITDA), a non-GAAP financial measure defined in Appendix F, by 2012 (which assumes an average power price on open positions of roughly $95/MWh on existing plants or deployment of capital resulting in additional earnings potential) generating cash flow for investment which would create additional EBITDA, debt repayment capacity and/or distributions through share repurchases in the range of up to $0.5 billion to $1 billion annually

Credit quality and flexibility to manage risk and act on opportunities:

• Entergy: investment grade credit with a lower risk profile
• Enexus: strong merchant credit, relative to others (subject to market terms and conditions, Enexus expects to execute up to $4.5 billion of debt financing)

The amount of repurchases may vary as a result of material changes in business results or capital spending or new investment opportunities. Entergy and Enexus further acknowledge that limitations presented by the current credit markets, as well as depressed power prices in markets where Enexus sells power, create implications for near-term financing plans and financial results. Should these conditions extend for a prolonged period, financial aspirations would likely be affected. At the same time, current market conditions also create potential capital deployment opportunities for companies with ample liquidity which in turn creates opportunity to grow EBITDA.

2012 aspirations can be considered in association with financial sensitivities as shown in Table 11. These sensitivities illustrate the estimated change in aspiration resulting from changes in aspiration drivers. Estimated impacts shown in Table 11 are intended to be illustrative.

Table 11: 2012 Financial Sensitivities
Aspiration	2012 Aspiration Assumption	Drivers	Estimated Annual Impact
Entergy			(Per share in U.S. $) (i)
Earnings growth	6 - 8% earnings per share CAGR; 50% from $2.5 billion post-spin share repurchase program and balance from Utility organic growth	1% sales growth $100 million/year investment in service 1% change in allowed ROE 1% change in non-fuel operation and maintenance expense $100 million change in debt $500 million share repurchase post-spin	- / + 0.11 + 0.03 - / + 0.33 - / + 0.06 - / + 0.02 +0.12 - 0.15
Enexus			(EBITDA in U.S. $; millions)
EBITDA	$2 billion EBITDA	+0 - 1,500 Btu/KWh heat rate expansion +$0 - 30/ton CO2 +$0 - 4/kW-mo. capacity price - / + $0 - 2/MMBtu change in gas price	Up to 400 Up to 600 Up to 200 Down/Up to 600
	$0.5 - $1 billion annual share repurchase, debt repayment and/or investment capacity	$1 billion investment, assuming 40-year life and 13% weighted average cost of capital	+ 200
(i) Based on estimated 2009 average fully diluted shares outstanding of approximately 194 million.

Transaction Timing

The state regulatory decisions and financing continue as the critical path items. Due to the continued turmoil in the financial markets and a longer regulatory approval process than originally expected, Entergy and Enexus remain in a rolling readiness posture. This strategy enables Entergy to execute the spin-off following receipt of regulatory approvals and once the timing is right to access the credit markets, both on acceptable terms. The transaction is expected to close on a month end. The transactions are subject to various approvals, outlined in the following table. Final terms of the transactions and spin-off completion are subject to the subsequent approval of the Entergy Board of Directors. Citigroup and Goldman Sachs are serving as Entergy's financial advisors in this process.

Proceeding	Pending Regulatory Approvals - Spin-Off of Non-Utility Nuclear Business
Nuclear Regulatory Commission	The NRC approved Entergy Nuclear Operations, Inc.'s (ENO) application on July 28, 2008. The approval remains effective until July 28, 2009, at which time ENO may seek to extend the effective period.
Vermont Public Service Board	Request: On January 28, 2008, pursuant to 30 V.S.A. Sections 107, 108, 231 and 232, Entergy Nuclear Vermont Yankee, L.L.C. (EVY) and ENO requested approval from the Vermont Public Service Board (VPSB) for the indirect transfer of control, consent to pledge assets, guarantees and assignments of contracts, amendment to Certificate of Public Good (CPG) to reflect name change, replacement of guaranty and substitution of a credit support agreement. Recent Activity: None Next Steps: All scheduled procedural steps have been completed and a decision from the VPSB is now pending. Other Background: Under Vermont law, approval requires a finding that actions promote the general good of the state. In accordance with the VPSB scheduling order, testimony has been filed and the discovery process is complete. Two days of technical hearings were held on July 29 and 30, 2008, and final reply briefs were filed on August 20, 2008. The fundamental positions of the parties remain essentially unchanged with opposition to the spin-off coming from the Department of Public Service, and support for the spin-off coming from the Vermont Utilities.
New York Public Service Commission	Request: On January 28, 2008, pursuant to New York State Public Service Law (NYPSL) Sections 69 and 70, Entergy Nuclear FitzPatrick, L.L.C. (ENFP), Entergy Nuclear Indian Point 2 and 3, L.L.C. (ENIP2 & 3), ENO and corporate affiliate Enexus (formerly referred to as NewCo and SpinCo) filed a petition with the New York Public Service Commission (NYPSC) requesting a declaratory ruling regarding corporate reorganization or in the alternative an order approving the transaction and an order approving debt financing. Petitioners also requested confirmation that the corporate reorganization will not have an impact on ENFP's, ENIP2 & 3's, and ENO's status as lightly regulated entities, given they will continue to be competitive wholesale generators. Recent Activity: None Next Steps: Absent a settlement, the Administrative Law Judges (ALJs) will submit a recommendation to the NYPSC with respect to the transaction. Other Background: Entergy requested that the NYPSC consider the spin-off transaction consistent with a lightened regulatory regime for wholesale generators in New York, including owners and operators of nuclear generating facilities, under which PSL 70 review of changes in ownership is not required. Approval under Section 70 of the NYPSL requires a finding that actions are in the public interest. Three parties filed comments in response to Entergy's petition, and several other parties also requested to be added to the service list for the proceeding. In response to Entergy's petition, in an order dated May 23, 2008, the NYPSC declined to issue a declaratory ruling approving the transaction and to consider the transaction as one consistent with lightly-regulated generators under PSL 70. In its order, the NYPSC noted that these nuclear plants "are crucial to the adequacy of generation supply within New York" and as such additional proceedings were deemed necessary. The NYPSC established a 60 day discovery period, which initially expired on July 22, 2008, but was extended for a short period by the two assigned ALJs and expired on September 29, 2008. The fundamental positions of the parties remain essentially unchanged with opposition to the spin-off coming from the Attorney General of New York and Westchester County, New York. Support for the spin-off, conditioned on specific financial parameters, has come from the staff of the NYPSC. On October 23, 2008, the ALJs issued notification to all parties that from their review of the submissions, all issues of fact and policy material to the relief requested by Petitioners have been thoroughly addressed by the parties, an adequate record for decision is available to the Commission, and no further formal proceedings are warranted. On December 11, 2008, notice was provided that the parties intended to conduct a settlement discussion which to date has not yielded an acceptable agreement.
Federal Energy Regulatory Commission	FERC approved the ENO application on June 12, 2008. The approval remains effective for a reasonable period of time assuming the proposed transaction is not materially altered.
Securities and Exchange Commission	Request/Recent Activity: None Next Steps: The SEC is expected to ultimately declare the filing effective shortly before the spin-off is consummated. Other Background: Pursuant to Section 12 of the 34 Exchange Act, a Form 10 information statement is required to be filed to register securities with the SEC. The Form 10 is furnished in connection with the distribution by Entergy to its common shareholders of all of the shares of the common stock of Enexus. The information statement describes the distribution in detail and contains information about Enexus, its business, financial condition and operations. The Form 10 is subject to review and comments by the SEC staff and will need to be declared effective prior to the distribution. The Form 10 was initially filed on May 12, 2008, with first, second, and third amendments filed on July 31, September 12, and November 21, 2008. The SEC comments to date have related primarily to accounting and disclosure items.

Appendix B-1 provides details of first quarter 2009 vs. 2008 earnings variance analysis for "Utility, Parent & Other," "Competitive Businesses," and "Consolidated."

Appendix B-1: As-Reported Earnings Per Share Variance Analysis
First Quarter 2009 vs. 2008
(Per share in U.S. $, sorted in consolidated column, most to least favorable)
	Utility		Competitive
	Parent & Other		Business		Consolidated
2008 earnings	0.48		1.08		1.56
Interest and other charges	0.02		0.03		0.05
Decommissioning expense	(0.01)		-		(0.01)
Nuclear refueling outage expense	(0.02)		-		(0.02)
Depreciation/amortization expense	(0.03)		(0.01)		(0.04)
Other income (deductions)	0.01		(0.06)	(j)	(0.05)
Income taxes - other	(0.02)		(0.03)		(0.05)
Net revenue	0.01		(0.07)	(k)	(0.06)
Taxes other than income taxes	(0.07)	(l)	(0.01)		(0.08)
Other operation & maintenance expense	(0.05)	(m)	(0.05)	(n)	(0.10)
2009 earnings	0.32		0.88		1.20

10. The decrease is due primarily to an impairment associated with decommissioning trust fund investments.
11. The decrease is due primarily to lower revenues at Entergy Nuclear from lower production due to increased number of planned refueling outage days during the quarter and lower revenue amortization for the Palisades below-market Power Purchase Agreement.
12. The increase is due primarily to the absence in the current period of the effects of a favorable resolution of a tax audit issue in first quarter 2008, which is partially offset in net revenue, and higher ad valorem and franchise taxes.
13. The increase is due primarily to expenses recorded at the Parent for outside services to pursue the non-utility nuclear spin-off.
14. The increase is due primarily to non-utility nuclear spin-off dis-synergy expenses incurred at Entergy Nuclear.

Appendix B-2 lists special items by business with quarter-to-quarter comparisons. Amounts are shown on both earnings per share and net income bases. Special items are those events that are less routine, are related to prior periods, or are related to discontinued businesses. Special items are included in as-reported earnings per share consistent with generally accepted accounting principles (GAAP), but are excluded from operational earnings per share. As a result, operational earnings per share is considered a non-GAAP measure.

Appendix B-2: Special Items (shown as positive / (negative) impact on earnings)
First Quarter and 2009 vs. 2008
(Per share in U.S. $)
	First Quarter
	2009	2008	Change
Utility, Parent & Other
Non-Utility Nuclear spin-off expenses	(0.05)	-	(0.05)
Competitive Businesses
Entergy Nuclear
Non-Utility Nuclear spin-off dis-synergies	(0.04)	-	(0.04)
Non-Nuclear Wholesale Assets	-	-	-
Total Competitive Businesses	(0.04)	-	(0.04)
Total Special Items	(0.09)	-	(0.09)
(U.S. $ in millions)
	First Quarter
	2009	2008	Change
Utility, Parent & Other
Non-Utility Nuclear spin-off expenses	(10.6)	-	(10.6)
Competitive Businesses
Entergy Nuclear
Non-Utility Nuclear spin-off dis-synergies	(6.6)	-	(6.6)
Non-Nuclear Wholesale Assets	-	-	-
Total Competitive Businesses	(6.6)	-	(6.6)
Total Special Items	(17.2)	-	(17.2)

Appendix C provides a summary of selected regulatory cases and events that are pending.

Appendix C: Regulatory Summary Table
Company/ Proceeding	Authorized ROE	Pending Cases/Events
Retail Regulation
Entergy Arkansas	9.9%	Recent activity: On April 23, 2009, the Arkansas Supreme Court denied EAI's petition for review of the Court of Appeals decision. Background: On August 25, 2006, EAI filed a rate case requesting a $150 million increase based on a June 30, 2006 test year using an 11.25% ROE. The rate increase was revised to $106.5 million on rebuttal primarily to remove a plant acquisition included in the initial filing. The APSC order called for a $5.1 million rate reduction, 9.9% ROE and a hypothetical common equity level lower than EAI's actual capital structure. The base rate change was implemented August 29, 2007. EAI filed an appeal of the rate case order, following earlier denial of EAI's request for rehearing on its case. On December 17, 2008, the Arkansas Court of Appeals issued its decision, upholding almost all aspects of the APSC decision on EAI's rate case. Considering the progress of the proceeding, EAI recorded a charge associated with costs previously accumulated in EAI's storm reserve and removal costs associated with the termination of a lease that were not approved for recovery by the APSC in its rate case order. On January 5, 2009, EAI filed a petition for review before the Arkansas Supreme Court, requesting a review of the appeal decision. Storm Cost Recovery: Recovery of 2008 extraordinary storm restoration costs commenced in January 2009. Later that month, EAI was struck by a severe ice storm with restoration cost estimates standing at $120 to $140 million. Considering the magnitude of the statewide storm damages, the Arkansas legislature passed legislation authorizing storm reserve accounting in March 2009, followed by the enactment of storm securitization legislation in April. Both pieces of legislation are effective for storms occurring on or after January 1, 2009. At the end of March, EAI filed a petition with the APSC to establish storm reserve accounting pursuant to the legislation. In the interim, the APSC approved on March 6, 2009 EAI's application for an accounting order authorizing the deferral of the operating and maintenance cost portion of the ice storm restoration costs pending their recovery. Finally, on April 1, 2009, EAI filed its earnings analysis test pursuant to the 2008 extraordinary storm recovery order indicating a $40.1 million revenue deficit and a resulting 7.9% regulatory ROE. Background: As a result of the 2007 rate case order, EAI was required to discontinue storm reserve accounting and became subject to an annual $14.4 million budget for allowed storm recovery by the APSC. In its subsequent December 2007 consolidated order, the APSC indicated that it was open to consideration of alternative extraordinary storm restoration cost methodologies that are both fair and reasonable to rate payers and in the public interest. Considering the effects of hurricanes Gustav and Ike, compounded by other storms earlier in the year, EAI pursued extraordinary storm recovery. On December 19, 2008, the APSC approved EAI's request to defer 2008 extraordinary storm restoration costs for recovery via the Storm Damage Rider in 2009. The APSC reduced EAI's request by $4 million to allow for standard variation in storm costs from the normalized level in base rates. EAI is permitted to recover the retail portion of $22.3 million, subject to adjustments arising from storm cost audit, earnings review and other items consistent with past APSC regulatory practice. Storm-related capital costs were not included. EAI's filing proposed the underlying costs would be subject to audit and an earnings review, with any over-earnings to be applied to the deferral balance. White Bluff Environmental Controls Project: On March 27, 2009, EAI petitioned the APSC to undertake the Environmental Controls project that will install scrubbers and low NOx burners at the co-owned White Bluff coal plant at an expected total cost of approximately $1.0 billion, with EAI's share at $631 million. EAI requested that the APSC issue an order by September 25, 2009, given EAI may be required to make significant commitments in fourth quarter 2009 in order to meet the 2013 compliance deadline. Later in the year, EAI intends to file an interim rate schedule with the APSC pursuant to Act 310 for recovery of costs incurred as of that time and intends to amend the interim rate schedule approximately every six months to capture ongoing costs. Background: White Bluff Units 1 and 2 are required to meet more stringent NOx and SO2 limits by 2013 in order to comply with the Arkansas Department of Environmental Quality State Implementation Plan regulations implementing the United States Environmental Protection Agency's Regional Haze Rule. To continue operating, White Bluff must install pollution control technology. EAI has conducted economic analysis comparing the Environmental Controls project to other supply options for capacity and energy and concluded the project is the lowest reasonable cost alternative under a wide range of assumptions.
Entergy Texas	10.00%	Recent activity: On March 11, 2009, the PUCT approved the unanimous settlement which implemented interim rates effective January 28, 2009, for usage beginning December 19, 2008. The black box settlement called for a $46.7 million base rate increase, among other details, and stipulated 10% as a reasonable ROE. Background: On September 26, 2007, ETI filed a rate case consisting of three major requests for relief: a $64.3 million base rate increase, a $43.2 million request for various riders, and a fuel reconciliation for the period January 2006 through March 2007 in the amount of $858 million. The rate case was based on a March 31, 2007 test year using an 11% ROE. Two competing non-unanimous settlement agreements were ultimately introduced and rejected. A unanimous settlement was reached by parties on December 16, 2008. Prior to the settlement, ETI operated under a base rate freeze since 1999. Legislation enacted in June 2005 extended the base rate freeze to mid 2008 but allowed ETI to file for rate relief through riders for incremental capacity costs (IPCR) and transition costs. In December 2005, the PUCT approved recovery of $18 million annual capacity costs, subject to reconciliation from September 2005. On January 23, 2008, an agreement was filed with the PUCT to increase the IPCR to $21 million and to add a surcharge for $10.3 million of unrecovered costs. In June 2006, the PUCT approved a settlement in the Transition to Competition (TTC) Cost recovery case, allowing ETI to recover $14.5 million per year in TTC costs over a 15-year period. The unanimous settlement eliminates the IPCR rider but does not affect the TTC rider.

Appendix C: Regulatory Summary Table (continued)
Company/ Proceeding	Authorized ROE	Pending Cases/Events
Retail Regulation
Entergy Texas		Qualified Power Region: On April 29, 2009, ETI filed its updated TTC plan indicating that it is agreeable to either stay in the Southeastern Reliability Council (SERC) or move to ERCOT, depending on the PUCT's policy direction. A prehearing conference is scheduled for May 11, 2009 to address the remainder of the procedural schedule. In addition, legislation has been introduced in Texas addressing TTC. In its current form, the legislation calls for ETI to cease all TTC activities, provides ETI the opportunity to recover certain transmission costs consistent with other companies outside of ERCOT to the extent not otherwise recovered and requires ETI to propose a competitive generation tariff. The legislation indicates the PUCT may initiate a proceeding to certify a power region when conditions supporting such a proceeding exist and that the PUCT may not approve a TTC plan until the expiration of four years from the time the region is certified. The Texas legislature adjourns June 1, 2009. Background: In December 2006, ETI filed a TTC plan with the PUCT, proposing ETI join ERCOT as it represents the most viable path to full customer choice. To support a PUCT decision on the appropriate qualified power region, in October and November 2007, the PUCT issued orders in ETI's TTC case requiring further studies and approving Southwest Power Pool's (SPP) plan to develop information similar to that prepared by ERCOT and requiring an updated analysis of the benefits of ETI remaining in SERC. In May 2008, the PUCT issued an order directing ERCOT to update its study. In December 2008, ETI, ERCOT and SPP submitted updated studies. ERCOT filed a minor revision to its study on April 15, 2009 to incorporate additional contingencies. Storm Cost Recovery: On April 16, 2009, Governor Perry signed Senate Bill (SB) 769 enacting evergreen securitization legislation for recovery of system restoration costs, enabling ETI to initiate its storm recovery proceeding on April 21, 2009. ETI seeks recovery of $577.5 million of system restoration costs incurred through February 28, 2009, plus certain estimates, and authorization to recover in a financing proceeding to be subsequently filed, carrying costs on the approved system restoration costs at ETI's weighted average cost of capital (WACC). Background: Pursuant to SB 769, the PUCT has 150 days after a company makes its filing to provide an order determining the amount eligible for recovery and securitization. A company may file for a financing order prior to the expiration of the 150-day period. The PUCT has 90 days after the company makes its filing to issue a financing order, but need not issue an order until it has determined costs eligible for recovery and securitization. The legislation also calls for system restoration costs to include carrying costs using the last approved WACC from the date on which system restoration costs were incurred until the date transition bonds are issued pursuant to a financing order or until costs are otherwise recovered pursuant to SB 769.
Entergy Gulf States Louisiana	9.90% - 11.40%	Recent activity: The LPSC Staff continues to review the 2007 test year Formula Rate Plan (FRP) filing. Rate changes to date for the filing, subject to refund, include the $5.6 million revenue deficiency plus $21.2 million for capacity cost recovery. Background: In March 2005, the LPSC approved a Global Settlement which established an FRP with a 10.65% ROE midpoint and a +/- 75 basis point bandwidth and a recovery mechanism for Commission-approved capacity additions. Earnings outside the bandwidth are allocated 60% to customers and 40% to the company. On August 25, 2008, EGSL filed to implement rates for the 2007 test year filing subject to refund effective for the first billing cycle of September. The August 25, 2008 filing indicated a 9.23% ROE, which is below the allowed bandwidth. The $5.6 million revenue deficiency was partially offset by $4.1 million reduced capacity cost recovery, with subsequent capacity approvals increasing rates an additional $25.3 million. On September 29, 2008, EGSL filed to implement a further increase for the Ouachita Purchased Power Agreement (PPA) and filed on November 25, 2008 to implement an increase for the Calpine Carville PPA. The 2006 test year filing was the third of three approved filings by the LPSC. The FRP may be extended by mutual agreement of EGSL and the LPSC, and the parties agreed to extend the FRP one additional year. EGSL is interested in pursuing a further extension and continues to have discussions with the LPSC Staff concerning this matter. Storm Cost Recovery: EGSL anticipates initiating its storm proceeding in the very near future. Background: EGSL's restoration cost estimate for hurricanes Gustav and Ike is $240 to $255 million. In lieu of seeking interim recovery, on October 9, 2008, EGSL accessed $85 million of storm reserves funded by securitized debt proceeds. On October 15, 2008, the LPSC approved EGSL's request to defer and accrue carrying cost on unrecovered storm expenditures during the period the company seeks regulatory recovery. The approval was without prejudice to the ultimate resolution of the total amount of prudently incurred storm cost or final carrying cost rate. New securitization legislation is not needed, as existing legislation extends to Gustav and Ike.
Entergy Louisiana	9.45% - 11.05%	Recent activity: On March 23, 2009, the Administrative Law Judge (ALJ) ruled against ELL on 2006 test year issues subject to hearing in the fall of 2008. On April 6, 2009, ELL filed exceptions to the proposed ALJ recommendations on the three remaining issues, Cash Point, stock options and fixed cost contribution from lost customers. LPSC Staff and intervenors have since filed replies to ELL's exceptions. The ALJ will submit a final recommendation to the LPSC for a vote which could come this summer. The test year 2007 FRP outcome is also pending. Background: In May 2005, the LPSC approved a settlement reestablishing the Company's FRP with a 10.25% ROE midpoint and a +/- 80 basis point bandwidth and a recovery mechanism for Commission-approved capacity additions. Earnings outside the bandwidth are allocated 60% to customers and 40% to the company. The 2007 test year filing is the third of three approved filings by the LPSC. The FRP may be extended by the mutual agreement of ELL and the LPSC. ELL is interested in pursuing an extension and continues to have discussions with the LPSC Staff concerning this matter. ELL's 2006 test year filing made in May 2007 indicated a 7.6% ROE. On September 27, 2007, ELL implemented an $18.4 million increase, subject to refund, $23.8 million representing a 60% adjustment to reach the bottom of the FRP band, net of $5.4 million for reduced capacity cost recovery. The LPSC allowed ELL to defer the difference between the $39.8 million requested for unrecovered fixed costs for extraordinary customer losses associated with Hurricane Katrina and the $23.8 million 60% adjustment as a regulatory asset, pending ultimate LPSC resolution of the 2006 FRP filing. On October 29, 2007, ELL implemented a $7.1 million FRP decrease which is primarily due to the reclassification of certain franchise fees from base rates to collection via a line item on customer's bills pursuant to an LPSC General Order. On August 25, 2008, ELL filed to implement rates for the 2007 test year filing subject to refund, effective for the first billing cycle of September. The August 25, 2008 filing indicated a 9.14% ROE, which is below the allowed bandwidth. The new rates reflect a $4.3 million revenue deficiency plus $12.6 million of additional capacity cost recovery. ELL also continues to seek resolutions of its 2006 test year FRP filing, including extraordinary customer loss recovery, and a hearing was conducted at the end of September 2008. ELL continued to pursue extraordinary customer losses in its 2007 test year filing by submitting a second scenario of the filing reflecting unrecovered fixed costs.

Appendix C: Regulatory Summary Table (continued)
Company/ Proceeding	Authorized ROE	Pending Cases/Events
Retail Regulation
		Storm Cost Recovery: ELL anticipates initiating its storm proceeding in the very near future. Background: ELL's restoration cost estimate for hurricanes Gustav and Ike is $390 to $405 million. In lieu of seeking interim recovery, on October 9, 2008, ELL accessed $134 million of storm reserves funded by securitized debt proceeds. On October 15, 2008, the LPSC approved ELL's request to defer and accrue carrying cost on unrecovered storm expenditures during the period the company seeks regulatory recovery. The approval was without prejudice to the ultimate resolution of the total amount of prudently incurred storm cost or final carrying cost rate. New securitization legislation is not needed, as existing legislation extends to Gustav and Ike. Little Gypsy Repowering: On March 11, 2009, the LPSC issued an order directing ELL to temporarily suspend the Little Gypsy Repowering Project and file a report with the LPSC on the economic viability of the project and develop a recommendation regarding whether to delay the project for an extended time. This action was based upon a number of factors including the recent decline in natural gas prices, as well as environmental concerns, the unknown costs of carbon legislation and changes in the capital/financial markets. On April 1, 2009, ELL recommended to the LPSC that it continue the temporary project suspension and make a filing with the LPSC seeking a longer-term suspension (three years or more) of the project. The LPSC order approving the project includes a recovery provision for prudently incurred costs in the event circumstances changed materially. The filing indicated approximately $160 million of spending through February 28, 2009 and estimated approximately $300 million of total costs if the project is cancelled. ELL had obtained all major environmental permits required to begin construction. A longer-term delay places these permits at risk and may adversely affect the project's economics and technological feasibility in the event the project is re-initiated. The LPSC discussed the filing at its business and executive session on April 8, 2009, and ELL plans to proceed as outlined in the recommendation. On April 21, 2009, the LPSC extended the temporary suspension of the Phase II procedural schedule and ordered that within 60 days, ELL/EGSL make a further filing seeking action with respect to the Phase II claims as appropriate under whatever ruling is forthcoming from the LPSC regarding the future of the Little Gypsy project. Background: On November 8, 2007, the LPSC voted unanimously to approve ELL's request to repower the 538 MW Little Gypsy unit to utilize CFB technology relying on a dual-fuel approach (petroleum coke and coal), an action that could reduce Louisiana customers' dependence on natural gas. The approval was subject to a number of conditions, including the development and approval of a construction monitoring plan. On December 21, 2007, ELL initiated a Phase II proceeding seeking cash earnings on CWIP and approval for the procedure to synchronize permanent base rate recovery when the project is placed in service, via an FRP or base rate filing. This proceeding was suspended temporarily to allow ELL to develop an updated project cost estimate and schedule to account for a delay resulting from the need to conduct additional environmental analysis (Maximum Achievable Control Technology application) as a result of a federal court decision in February 2008 unrelated to the project. The additional analysis estimated construction could commence by mid-year 2009 leading to a targeted in service date by mid-year 2013 and resulting in a project cost estimate increase to $1.76 billion. ELL made its first quarterly monitoring plan filing at the end of July and on October 16, 2008 supplemented and resumed its Phase II proceeding, adding a recommendation to allocate one-third of the project to EGSL. On December 9, 2008, ELL filed a motion to consolidate the Waterford 3 Steam Generator Replacement Phase II filing request for cash earnings on CWIP with the Little Gypsy Phase II filing. In February 2009, the Louisiana Department of Environmental Quality issued the new air permit. ELL also continued to make its quarterly monitoring plan filings. Waterford 3 Steam Generator Replacement: ELL is evaluating next steps for the Phase II request for cash earnings on CWIP for the steam generator replacement project while the consolidated Little Gypsy/Waterford 3 proceeding is temporarily suspended. On March 31, 2009, ELL filed its first quarterly monitoring report detailing progress on the project to date. Background: On June 26, 2008, ELL petitioned the LPSC to replace two steam generators, the reactor vessel closure head and control drive mechanisms, at an expected cost of $511 million. The petition seeks relief in two phases. Phase I seeks certification within 120 days that the public convenience and necessity would be served by undertaking this project. Among other relief requested, ELL is also seeking approval for the procedure to synchronize permanent base rate recovery when the project is placed in service, via an FRP or base rate filing. In its Phase II filing, ELL is seeking cash earnings on CWIP. Due to careful maintenance, Waterford 3 is one of the last nuclear plants of its type to have to replace its steam generators. Of the 14 plants in the U.S. with similar pressurized water reactor designs, only one other plant has not replaced the equipment already. Replacing the reactor vessel closure head and control element drive mechanisms at the same time allows ELL to do the work more efficiently and economically. The long-lead time to design, manufacture and transport some of the required equipment to the site requires approval now in order to perform the project in 2011. On November 12, 2008, the LPSC approved the stipulated settlement, finding that the decision to undertake this project at an estimated cost of $511 million is prudent and the timing concurrent with the 2011 outage is reasonable. Prudent costs will be eligible for recovery through ELL's formula rate plan, if extended, or a base rate case filing. ELL shall undertake a future prudence review to consider at least project management, cost controls, success in achieving stated objectives, project replacement cost, and outage length / replacement power costs. ELL will also provide high level quarterly status reports on budget, schedule and business issues. On December 9, 2008, ELL initiated the filing to consolidate the Phase II request with the Little Gypsy Phase II proceeding, consistent with the LPSC's direction.

Appendix C: Regulatory Summary Table (continued)
Company/ Proceeding	Authorized ROE			Pending Cases/Events
Retail Regulation
Entergy Mississippi			9.46% - 12.24%			Recent activity: On March 13, 2009, EMI made its 2008 test year FRP filing indicating an earned ROE of 7.41% compared to a 13.16% midpoint ROE, including 69 basis points for performance incentives (band is 11.91% - 14.42%). The filing indicated a $27 million revenue deficiency, with a $14.5 million maximum increase allowed. The Mississippi Public Utilities Staff (MPUS) has since disputed the filing, extending the resolution deadline to June 30, 2009. Any approved changes in rates would be effective for bills rendered on and after May 1, 2009. In addition, on March 31, 2009, the Mississippi Supreme Court issued a briefing schedule in the 2007 test year FRP appeal case, with EMI's brief due May 11, 2009, followed 30 days later by the MPSC's reply brief. Background: EMI has been operating under a FRP last approved in December 2002. The FRP allows the company's earned ROE to increase or decrease within a bandwidth with no change in rates. Earnings outside the bandwidth are allocated 50% to customers and 50% to the company, but on a prospective basis only. The plan also provides for performance incentives that can increase or decrease the benchmark ROE by as much as 100 basis points. On March 14, 2008, EMI made its 2007 test year FRP filing indicating an earned ROE of 9.42% compared to a 12.34% midpoint ROE, including 92 basis points for performance incentives (band is 11.08% - 13.6%). The filing called for an annual revenue increase of $10.1 million. On June 20, 2008, EMI reached a settlement with the MPUS, resulting in a $3.775 million rate increase. On January 8, 2009, the MPSC rejected the MPUS settlement, finding that rates currently in effect are just and reasonable and shall continue in effect pending the MPSC's review of the provisions of the rider FRP and possible amendments thereto. On January 22, 2009, EMI appealed the MPSC decision to the Mississippi Supreme Court, given the order denied the settlement increase with virtually no explanation. Fuel Recovery/Attorney General Complaint: The MPSC continues to investigate issues associated with EMI fuel costs and claims raised by the Mississippi Attorney General (AG) going back some 30 years. On February 10, 2009, an independent audit report commissioned by the MPSC to review fuel recovery was issued. The report indicated that many of EMI's fuel procurement and adjustment practices are sound and in the customers' best interest. Background: The relatively new Commission has been reviewing state utilities' practices and procedures, most notably related to fuel recovery. EMI understands the MPSC's need to obtain more information about past Commission actions, system tariffs, and issues including fuel purchases, fuel costs and power generation needs, and will continue to work with the Commission to inform, respond to questions and develop alternative policies on tariffs if they are found to be in the best interests of customers and fairly balanced with other stakeholder rights. In addition, the AG issued civil investigative demands directed at EMI and other Entergy companies related to EMI's fuel adjustment clause and other matters. The AG voluntarily dismissed this proceeding, and instead filed a complaint in state court in December 2008 against EMI and other Entergy companies alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution. The litigation is wide ranging and relates to tariffs and procedures under which EMI obtains power in the wholesale market to meet electricity demand. EMI believes the complaint is unfounded, should be resolved in the appropriate regulatory forum and should not be tried in the court of public opinion. On December 29, 2008, the affected Entergy companies filed to remove the AG's suit to U.S. District Court (the appropriate forum to resolve the types of federal issues raised in the suit) where it is currently pending, and additionally answered the complaint and filed a counter-claim for injunctive and other relief based upon the Mississippi Public Utilities Act and the Federal Power Act. The AG has filed a pleading seeking to remand the case to state court. Storm Cost Recovery: EMI continues to evaluate whether the storm restoration costs will meet the threshold to draw upon the reserves. Background: EMI's restoration cost estimate for Hurricane Gustav is $18 to $20 million. As of the end of March, EMI had $32 million of storm reserves funded by securitized debt proceeds.
Entergy New Orleans		11.1% Electric 10.75% Gas			Recent activity: On April 2, 2009, the City Council of New Orleans (CCNO) approved a comprehensive settlement for ENOI's rate case. Key provisions of the agreement include a total electric bill reduction of $35.3 million, including conversion of the $10.6 million voluntary recovery credit to a permanent reduction and complete realignment of Grand Gulf recovery from fuel to base rates, and a $4.95 million gas rate increase, both effective June 1, 2009. A new three year FRP was also adopted, with terms including an 11.1% electric ROE and a +/- 40 basis point bandwidth and a 10.75% gas ROE with a +/- 50 basis point bandwidth. Earnings outside the bandwidth reset prospectively to the midpoint ROE, with the difference flowing to customers or the company depending on whether ENOI is over or under-earning. The FRP also includes a recovery mechanism for Council-approved capacity additions, plus provisions for extraordinary cost changes and force majeure. Finally, the settlement implements energy conservation and demand programs, provides a right of first refusal for up to a 20 percent interest in a potential Amite South generation resource and includes the short-term opportunity to lock-in certain fuel costs for summer 2009 through a financial hedge. Background: Prior to Hurricane Katrina, ENOI operated under a FRP with a ROE midpoint of 10.75%, a 45% hypothetical equity ratio, and electric and gas ROE bandwidths of 100 and 50 basis points, respectively. Pursuant to the 2006 post-Katrina rate agreement, ENOI filed its required rate case on July 31, 2008. The filing included a Period I (12/31/07) and Period II (Pro forma 12/31/08) test year case. ENOI proposed to reduce electric rates by approximately $23 million and increase gas base rates by $9.1 million. The electric reductions included $12.3 million through the fuel adjustment clause to realign Grand Gulf non-fuel operations and maintenance recovery to base rates and $10.6 million to convert the voluntary recovery credit to a permanent reduction. The rate case proposed an 11.75% ROE. On November 13, 2008, ENOI amended its rate filing to incorporate storm reserve treatment inadvertently omitted from the 2008 forecast Period II pro forma test year. The order also allowed ENOI to seek reinstatement of an appropriate FRP following the resetting of rates in 2009. Further, with New Orleans' recovery also taking place faster than expected, in December 2007, ENOI announced a voluntary plan to return an estimated $10.6 million to customers through a 6.15% base rate credit on electric bills. Storm Cost Recovery: The ENOI comprehensive rate settlement also addressed storm recovery for hurricanes Gustav and Ike. ENOI will continue to access storm reserves until all deferred operation and maintenance costs have been recovered. Capital costs (including carrying charges) shall be included in rate base as of December 31, 2009 and reflected in ENOI's initial annual FRP filing. In the interim, when rates become effective June 1, 2009, ENOI shall include capital costs in a deferred asset account until ENOI begins recovering such costs through base rates, with said costs accruing carrying charges computed using ENOI's 2009 WACC or WACC as authorized in the rate settlement. Background: ENOI's restoration cost estimate for hurricanes Gustav and Ike is $28 to $35 million. On October 9, 2008, ENOI accessed $10 million of storm reserves.

Appendix C: Regulatory Summary Table (continued)
Company/ Proceeding	Authorized ROE		Pending Cases/Events
Wholesale Regulation (FERC)
System Energy Resources, Inc.		10.94%		Recent activity: None. Background: ROE approved by July 2001 FERC order.
System Agreement		NA		Recent activity: Further progress on a proposed framework for a Successor Arrangement to the System Agreement could be stalled until FERC resolves EAI's and EMI's notices of cancellation filing made February 2, 2009. Background: The System Agreement case addresses the allocation of production costs among the utility operating subsidiaries. In June 2005, the FERC issued its decision and established a bandwidth of +/- 11% to reallocate production costs and ordered that this approach be applied prospectively. In December 2005, FERC established, among other things, that 1) the bandwidth would be applied to calendar year 2006 actual production costs and 2) 2007 would be the first possible year of payments among Entergy's operating companies. The orders were appealed and the DC Circuit remanded to the FERC for reconsideration of the FERC's conclusion it did not have the authority to order refunds and the decision to delay the implementation of the bandwidth remedy. The remand is pending at FERC. The LPSC also appealed to the DC Circuit the FERC Orders approving the Operating Companies compliance filing implementing the bandwidth remedy. That appeal is currently pending before the Court, with oral argument scheduled for May 8, 2009. The Entergy Operating Companies submitted bandwidth filings for the calendar years 2006 and 2007 production costs. The Operating Companies will submit their next filing in May 2009. The calendar year 2008 preliminary estimate indicates a payment from EAI in the amount of $394 million collectively to EGSL, ETI, ELL and EMI. On September 23, 2008, the ALJ issued a decision regarding the initial bandwidth proceeding related to calendar year 2006 production costs, that concluded that, with one exception, the Operating Company calculation was appropriate and that the Operating Companies' production costs were prudently incurred. The one exception would require the Operating Companies to calculate nuclear depreciation/decommissioning for each facility based on the NRC license life. The hearing on the bandwidth proceeding related to calendar year 2007 production costs is currently scheduled to commence June 4, 2009. On September 19, 2008, FERC issued an order on rehearing in the proceeding involving the exclusion of interruptible loads from certain System Agreement calculations that concluded that FERC had authority to order refunds and that refunds were appropriate. The APSC and the Operating Companies appealed the FERC's orders to the DC Circuit. The System Agreement has been and continues to be the subject of ongoing litigation. As a result, EAI and EMI submitted their eight year notices to withdraw from the System Agreement in December 2005 and November 2007, respectively, and on February 2, 2009 filed with the FERC their notices of cancellation of their respective System Agreement rate schedules, effective December 2013 and November 2015, respectively. EAI and EMI have requested FERC issue a decision on the notices of cancellation by June 1, 2009 or, if further inquiry is necessary, that FERC institute a paper hearing to resolve the major policy and legal issues by the end of the year and then, if necessary, set any remaining factual questions for expedited hearing. The Operating Companies are considering a Successor Arrangement for the System Agreement.

Appendix D-1 provides comparative financial performance measures for the current quarter. Appendix D-2 provides historical financial performance measures and operating performance metrics for the trailing eight quarters. Financial performance measures in both tables include those calculated and presented in accordance with generally accepted accounting principles (GAAP), as well as those that are considered non-GAAP measures.

As-reported measures are computed in accordance with GAAP as they include all components of earnings, including special items. Operational measures are non-GAAP measures as they are calculated using operational earnings, which excludes the impact of special items. A reconciliation of operational measures to as-reported measures is provided in Appendix G.

Appendix D-1: GAAP and Non-GAAP Financial Performance Measures
First Quarter 2009 vs. 2008 (see appendix F for definitions of certain measures)
For 12 months ending March 31	2009	2008	Change
GAAP Measures
Return on average invested capital - as-reported	7.6%	8.8%	(1.2)%
Return on average common equity - as-reported	14.1%	15.9%	(1.8)%
Net margin - as-reported	8.8%	10.6%	(1.8)%
Cash flow interest coverage	6.5	4.9	1.6
Book value per share	$44.02	$39.99	$4.03
End of period shares outstanding (millions)	196.1	191.9	4.2
Non-GAAP Measures
Return on average invested capital - operational	8.0%	9.0%	(1.0)%
Return on average common equity - operational	15.0%	16.3%	(1.3)%
Net margin - operational	9.4%	10.8%	(1.4)%
As of March 31 ($ in millions)	2009	2008	Change
GAAP Measures
Cash and cash equivalents	1,803	916	887
Revolver capacity	725	1,503	(778)
Total debt	12,034	11,292	742
Debt to capital ratio	57.4%	58.6%	(1.2)%
Off-balance sheet liabilities:
Debt of joint ventures - Entergy's share	124	134	(10)
Leases - Entergy's share	449	508	(59)
Total off-balance sheet liabilities	573	642	(69)
Non-GAAP Measures
Total gross liquidity	2,528	2,419	109
Net debt to net capital ratio	53.4%	56.5%	(3.1)%
Net debt ratio including off-balance sheet liabilities	54.7%	58.0%	(3.3)%

Appendix D-2: Historical Performance Measures (see appendix F for definitions of measures)
			2Q07	3Q07	4Q07	1Q08		2Q08		3Q08		4Q08	1Q09	08YTD		09YTD
Financial
		EPS - as-reported ($)	1.32	2.30	0.96		1.56		1.37	2.41	0.89		1.20	1.56		1.20
		Less - special items ($)	0.00	0.00	(0.16)		0.00		(0.09)	(0.09)	(0.10)		(0.09)	0.00		(0.09)
		EPS - operational ($)	1.32	2.30	1.12		1.56		1.46	2.50	0.99		1.29	1.56		1.29
	Trailing Twelve Months
		ROIC - as-reported (%)	8.2	8.6	8.3		8.8		8.6	8.1	8.1		7.6
		ROIC - operational (%)	7.6	8.1	8.5		9.0		8.8	8.4	8.4		8.0
		ROE - as-reported (%)	14.2	14.6	14.1		15.9		16.3	15.6	15.4		14.1
		ROE - operational (%)	12.9	13.4	14.5		16.3		17.0	16.4	16.1		15.0
		Cash flow interest coverage	5.8	5.3	5.0		4.9		5.0	7.0	6.5		6.5
		Debt to capital ratio (%)	57.3	57.3	57.6		58.6		60.7	60.4	59.7		57.4
		Net debt/net capital ratio (%)	54.1	53.9	54.7		56.5		58.3	54.9	55.6		53.4
Utility
		GWh billed
		Residential	6,986	11,128	7,376		8,011		7,372	10,671	6,992		7,893	8,011	7,893
		Commercial & Gov't	7,043	8,748	7,290		6,807		7,275	8,646	6,992		6,756	6,807	6,756
		Industrial	9,813	10,120	9,729		9,377		9,730	10,110	8,626		8,139	9,377	8,139
		Wholesale	1,428	1,413	1,666		1,290		1,440	1,431	1,240		1,387	1,290	1,387
		O&M expense/MWh (o)	$19.01	$15.16	$20.16		$17.26		$19.48	$14.43	$23.95		$18.51	$17.26	$18.51
		Reliability
		SAIFI (p)	1.9	1.8	1.8		1.9		1.9	1.9	1.9		1.8	1.9	1.8
		SAIDI (p)	198	188	184		191		215	227	216		209	191	209
Nuclear
		Net MW in operation	4,998	4,998	4,998		4,998		4,998	4,998	4,998		4,998	4,998	4,998
		Avg. realized price per MWh	$51.28	$53.11	$51.52		$61.47		$58.22	$61.59	$56.69		$63.84	$61.47	$63.84
		Production cost/MWh (o)	$21.27	$20.90	$22.64		$19.98		$23.11	$21.77	$22.77		$23.14	$19.98	$23.14
		Non-fuel O&M expense/ purchased power per MWh (o)	$24.09	$22.40	$23.94		$20.20		$23.42	$21.19	$23.06		$22.44	$20.20	$22.44
		GWh billed	8,896	10,105	10,254		10,760		10,145	10,316	10,489		10,074	10,760	10,074
		Capacity factor	82%	93%	92%		97%		92%	95%	94%		92%	97%	92%
		(o) 4Q07 excludes the effect of the nuclear alignment special.     (p) Excludes impact of major storm activity.

Appendix E: Planned Capital Expenditures

Entergy's capital plan from 2009 through 2011 anticipates $6.5 billion for investment, including $2.5 billion of maintenance capital. The remaining $4.0 billion is for specific investments such as the balance of Utility storm capital spending and the Utility's portfolio transformation strategy, the steam generator replacement at Entergy Louisiana's Waterford 3 nuclear unit, environmental compliance spending (i.e., spending for the installation of scrubbers and low NOx burners at Entergy Arkansas' White Bluff coal plant), transmission upgrades, dry cask storage, nuclear license renewal efforts, NYPA value sharing, the Indian Point Independent Safety Evaluation, and other initiatives.

The three year capital plan includes $1.1 billion for the Little Gypsy repowering project for which Entergy Louisiana plans to make a filing seeking a long-term suspension (three years or more). Spending through December 31, 2008 was reported at $135 million. $300 million is the total projected spending in the event Little Gypsy is canceled. In addition, the Utility incurred additional storm spending for the January 2009 Arkansas ice storm ranging from $55 to $60 million.

Appendix E: 2009-2011 Planned Capital Expenditures
($ in millions) - Prepared January 2009	2009	2010	2011	Total
Maintenance capital
Utility, Parent & Other	746	723	721	2,190
Entergy Nuclear	90	84	94	268
Non-Nuclear Wholesale Assets	-	-	-	-
Subtotal	836	807	815	2,458
Other capital commitments
Utility, Parent & Other	806	993	1,074	2,873
Entergy Nuclear	357	277	262	896
Non-Nuclear Wholesale Assets	-	-	-	-
Subtotal	1,163	1,270	1,336	3,769
Total Planned Capital Expenditures	1,999	2,077	2,151	6,227
Storm Capital	164	44	35	243
Total Planned Capital Expenditures Including Storm Capital	2,163	2,121	2,186	6,470

Appendix F provides definitions of certain operational performance measures, as well as GAAP and non-GAAP financial measures, all of which are referenced in this release.

Appendix F: Definitions of Operational Performance Measures and GAAP and Non-GAAP Financial Measures
Utility
GWh billed	Total number of GWh billed to all retail and wholesale customers
Operation & maintenance expense	Operation, maintenance and refueling expenses per MWh of billed sales, excluding fuel
SAIFI	System average interruption frequency index; average number per customer per year
SAIDI	System average interruption duration index; average minutes per customer per year
Number of customers	Number of customers at end of period
Competitive Businesses
Planned TWh of generation	Amount of output expected to be generated by Entergy Nuclear for nuclear units considering plant operating characteristics, outage schedules, and expected market conditions which impact dispatch
Percent of planned generation sold forward	Percent of planned generation output sold forward under contracts, forward physical contracts, forward financial contracts or options (consistent with assumptions used in earnings guidance) that may or may not require regulatory approval
Unit-contingent	Transaction under which power is supplied from a specific generation asset; if the asset is unavailable, seller is not liable to buyer for any damages
Unit-contingent with availability guarantees	Transaction under which power is supplied from a specific generation asset; if the asset is unavailable, seller is not liable to buyer for any damages, unless the actual availability over a specified period of time is below an availability threshold specified in the contract
Firm LD	Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset) or settles financially on notional quantities; if a party fails to deliver or receive energy, defaulting party must compensate the other party as specified in the contract
Planned net MW in operation	Amount of capacity to be available to generate power considering uprates planned to be completed within the calendar year
Bundled energy & capacity contract	A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold
Capacity contract	A contract for the sale of the installed capacity product in regional markets managed by ISO New England and the New York Independent System Operator
Average contract price per MWh or per kW per month	Price at which generation output and/or capacity is expected to be sold to third parties, given existing contract or option exercise prices based on expected dispatch or capacity, excluding the revenue associated with the amortization of the below-market PPA for Palisades
Average contract revenue per MWh	Price at which the combination of generation output and capacity are expected to be sold to third parties, given existing contract or option exercise prices based on expected dispatch
Entergy Nuclear
Net MW in operation	Installed capacity owned and operated by Entergy Nuclear
Average realized price per MWh	As-reported revenue per MWh billed for all non-utility nuclear operations
Production cost per MWh	Fuel and non-fuel operation and maintenance expenses according to accounting standards that directly relate to the production of electricity per MWh
Non-fuel O&M expense/purchased power per MWh	Operation, maintenance and refueling expenses and purchased power per MWh billed, excluding fuel
GWh billed	Total number of GWh billed to all customers
Capacity factor	Normalized percentage of the period that the plant generates power
Refueling outage duration	Number of days lost for scheduled refueling outage during the period

Financial measures defined in the below table include measures prepared in accordance with generally accepted accounting principles, (GAAP), as well as non-GAAP measures. Non-GAAP measures are included in this release in order to provide metrics that remove the effect of less routine financial impacts from commonly used financial metrics.

Appendix F: Definitions of Operational Performance Measures and GAAP and Non-GAAP Financial Measures (continued)
Financial Measures - GAAP
Return on average invested capital - as-reported	12-months rolling earnings adjusted to include preferred dividends and tax-effected interest expense divided by average invested capital
Return on average common equity - as-reported	12-months rolling earnings divided by average common equity
Net margin - as-reported	12-months rolling earnings divided by 12 months rolling revenue
Cash flow interest coverage	12-months cash flow from operating activities plus 12-months rolling interest paid, divided by interest expense
Book value per share	Common equity divided by end of period shares outstanding
Revolver capacity	Amount of undrawn capacity remaining on corporate and subsidiary revolvers
Total debt	Sum of short-term and long-term debt, notes payable, capital leases, and preferred stock with sinking fund on the balance sheet less non-recourse debt, if any
Debt of joint ventures (Entergy's share)	Debt issued by Non-Nuclear Wholesale Assets business joint ventures
Leases (Entergy's share)	Operating leases held by subsidiaries capitalized at implicit interest rate
Debt to capital	Gross debt divided by total capitalization
Financial Measures - Non-GAAP
Operational earnings	As-reported earnings applicable to common stock adjusted to exclude the impact of special items
Return on average invested capital - operational	12-months rolling operational earnings adjusted to include preferred dividends and tax-effected interest expense divided by average invested capital
Return on average common equity - operational	12-months rolling operational earnings divided by average common equity
Net margin - operational	12-months rolling operational earnings divided by 12 months rolling revenue
Earnings before interest, income taxes, depreciation and amortization and interest and dividend income (EBITDA)	Net Income plus interest expense, income taxes, depreciation and amortization and miscellaneous other income less other income
Total gross liquidity	Sum of cash and revolver capacity
Net debt to net capital	Gross debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents
Net debt including off-balance sheet liabilities	Sum of gross debt and off-balance sheet debt less cash and cash equivalents divided by sum of total capitalization and off-balance sheet debt less cash and cash equivalents

Appendices G-1 and G-2 provide reconciliations of various non-GAAP financial measures disclosed in this release to their most comparable GAAP measure.

Appendix G-1: Reconciliation of GAAP to Non-GAAP Financial Measures - Return on Equity, Return on Invested Capital and Net Margin Metrics
($ in millions)	2Q07	3Q07	4Q07	1Q08	2Q08	3Q08	4Q08	1Q09
As-reported earnings-rolling 12 months (A)	1,137	1,209	1,135	1,231	1,235	1,244	1,221	1,147
Preferred dividends	26	25	25	24	23	21	20	20
Tax effected interest expense	365	392	392	396	390	375	374	366
As-reported earnings, rolling 12 months including preferred dividends and tax effected interest expense (B)	1,528	1,626	1,552	1,651	1,648	1,640	1,615	1,533
Special items in prior quarters	108	101	0	(32)	(32)	(50)	(35)	(55)
Special items 2Q07 thru 1Q09
Nuclear fleet alignment			(32)
Nuclear spin-off costs					(18)	(17)	(20)	(17)
Total special items (C)	108	101	(32)	(32)	(50)	(67)	(55)	(72)
Operational earnings, rolling 12 months including preferred dividends and tax effected interest expense (B-C)	1,420	1,525	1,584	1,683	1,698	1,707	1,670	1,605
Operational earnings, rolling 12 months (A-C)	1,029	1,108	1,167	1,263	1,285	1,311	1,276	1,219
Average invested capital (D)	18,652	18,866	18,721	18,790	19,244	20,236	19,927	20,126
Average common equity (E)	7,998	8,264	8,030	7,756	7,555	7,973	7,915	8,152
Operating revenues (F)	11,371	11,311	11,484	11,655	12,150	12,825	13,094	13,018
ROIC - as-reported (B/D)	8.2	8.6	8.3	8.8	8.6	8.1	8.1	7.6
ROIC - operational ((B-C)/D)	7.6	8.1	8.5	9.0	8.8	8.4	8.4	8.0
ROE - as-reported (A/E)	14.2	14.6	14.1	15.9	16.3	15.6	15.4	14.1
ROE - operational ((A-C)/E)	12.9	13.4	14.5	16.3	17.0	16.4	16.1	15.0
Net margin - as-reported (A/F)	10.0	10.7	9.9	10.6	10.2	9.7	9.3	8.8
Net margin - operational ((A-C)/F)	9.1	9.8	10.2	10.8	10.6	10.2	9.7	9.4

Appendix G-2: Reconciliation of GAAP to Non-GAAP Financial Measures - Credit and Liquidity Metrics
($ in millions)	2Q07	3Q07	4Q07	1Q08	2Q08	3Q08	4Q08	1Q09
Gross debt (A)	10,936	11,194	11,123	11,292	11,768	12,656	12,279	12,034
Less cash and cash equivalents (B)	1,320	1,467	1,254	916	1,086	2,556	1,920	1,803
Net debt (C)	9,616	9,728	9,869	10,376	10,682	10,100	10,359	10,231
Total capitalization (D)	19,088	19,529	19,297	19,276	19,401	20,944	20,557	20,975
Less cash and cash equivalents (B)	1,320	1,467	1,254	916	1,086	2,556	1,920	1,803
Net capital (E)	17,767	18,062	18,043	18,360	18,315	18,388	18,637	19,172
Debt to capital ratio % (A/D)	57.3	57.3	57.6	58.6	60.7	60.4	59.7	57.4
Net debt to net capital ratio % (C/E)	54.1	53.9	54.7	56.5	58.3	54.9	55.6	53.4
Off-balance sheet liabilities (F)	664	662	658	642	638	637	574	573
Net debt to net capital ratio including off-balance sheet liabilities % ((C+F)/(E+F))	55.8	55.5	56.3	58.0	59.7	56.4	56.9	54.7
Revolver capacity (G)	1,650	1,804	1,730	1,503	826	374	645	725
Gross liquidity (B+G)	2,970	3,271	2,984	2,419	1,912	2,930	2,565	2,528

Entergy Corporation's common stock is listed on the New York and Chicago exchanges under the symbol "ETR".

Additional investor information can be accessed on-line at
www.entergy.com/investor_relations

**********************************************************************************************************************

In this news release, and from time to time, Entergy Corporation makes certain "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Except to the extent required by the federal securities laws, Entergy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

Forward-looking statements involve a number of risks and uncertainties. There are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking statements, including (a) those factors discussed in (i) Entergy's Form 10-K for the year ended December 31, 2008 and (ii) Entergy's other reports and filings made under the Securities Exchange Act of 1934, (b) the uncertainties associated with efforts to remediate the effects of Hurricanes Gustav and Ike and the January 2009 Arkansas ice storm and recovery of costs associated with restoration, and (c) the following transactional factors (in addition to others described elsewhere in this news release and in subsequent securities filings): (i) risks inherent in the contemplated spin-off, joint venture and related transactions (including the level of debt to be incurred by Enexus Energy Corporation and the terms and costs related thereto), (ii) legislative and regulatory actions, and (iii) conditions of the capital markets during the periods covered by the forward-looking statements. Entergy cannot provide any assurances that the spin-off or any of the proposed transactions related thereto will be completed, nor can it give assurances as to the terms on which such transactions will be consummated. The transaction is subject to certain conditions precedent, including regulatory approvals and the final approval by the Board of Directors of Entergy.

Entergy Corporation
Consolidating Balance Sheet
March 31, 2009
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other	Competitive Businesses	Eliminations	Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents:
Cash	$ 89,906	$ 4,466	$ -	$ 94,372
Temporary cash investments	1,216,019	492,567	-	1,708,586
Total cash and cash equivalents	1,305,925	497,033	-	1,802,958
Securitization recovery trust account	19,893	-	-	19,893
Notes receivable	5,452	1,336,373	(1,341,825)	-
Accounts receivable:
Customer	441,621	175,511	-	617,132
Allowance for doubtful accounts	(25,859)	-	-	(25,859)
Associated companies	338,629	91,943	(430,572)	-
Other	139,561	15,468	-	155,029
Accrued unbilled revenues	248,683	-	-	248,683
Total accounts receivable	1,142,635	282,922	(430,572)	994,985
Deferred fuel costs	19,527	-	-	19,527
Accumulated deferred income taxes	36,232	-	-	36,232
Fuel inventory - at average cost	230,440	3,336	-	233,776
Materials and supplies - at average cost	505,347	276,932	-	782,279
Deferred nuclear refueling outage costs	82,500	136,736	-	219,236
System agreement cost equalization	394,000	-	-	394,000
Prepayments and other	163,064	256,343	(56,927)	362,480
TOTAL	3,905,015	2,789,675	(1,829,324)	4,865,366
OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity	7,321,710	(299,023)	(6,959,063)	63,624
Decommissioning trust funds	1,094,526	1,624,163	-	2,718,689
Non-utility property - at cost (less accumulated depreciation)	226,429	4,137	-	230,566
Other	105,445	10,833	(5,388)	110,890
TOTAL	8,748,110	1,340,110	(6,964,451)	3,123,769
PROPERTY, PLANT, AND EQUIPMENT
Electric	31,546,855	3,635,538	-	35,182,393
Property under capital lease	745,152	-	-	745,152
Natural gas	306,854	-	-	306,854
Construction work in progress	1,233,712	327,518	-	1,561,230
Nuclear fuel under capital lease	416,913	-	-	416,913
Nuclear fuel	161,029	511,271	-	672,300
TOTAL PROPERTY, PLANT AND EQUIPMENT	34,410,515	4,474,327	-	38,884,842
Less - accumulated depreciation and amortization	15,666,402	598,763	-	16,265,165
PROPERTY, PLANT AND EQUIPMENT - NET	18,744,113	3,875,564	-	22,619,677
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
SFAS 109 regulatory asset - net	607,706	-	-	607,706
Other regulatory assets	3,703,332	-	-	3,703,332
Deferred fuel costs	168,122	-	-	168,122
Goodwill	374,099	3,073	-	377,172
Other	755,382	914,596	(522,535)	1,147,443
TOTAL	5,608,641	917,669	(522,535)	6,003,775
TOTAL ASSETS	$ 37,005,879	$ 8,923,018	$ (9,316,310)	$ 36,612,587
*Totals may not foot due to rounding.
Entergy Corporation
Consolidating Balance Sheet
March 31, 2009
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other	Competitive Businesses	Eliminations	Consolidated
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Currently maturing long-term debt	$ 545,511	$ 30,136	$ -	$ 575,647
Notes payable:
Associated companies	1,324,210	17,615	(1,341,825)	-
Other	80,034	-	-	80,034
Account payable:
Associated companies	398,925	7,774	(406,699)	-
Other	662,590	211,478	-	874,068
Customer deposits	310,033	-	-	310,033
Taxes accrued	128,824	(66,398)	-	62,426
Interest accrued	147,799	2,097	-	149,896
Deferred fuel costs	311,482	-	-	311,482
Obligations under capital leases	162,415	-	-	162,415
Pension and other postretirement liabilities	33,595	4,743	-	38,338
System agreement cost equalization	460,315	-	-	460,315
Other	163,090	125,000	(58,627)	229,463
TOTAL	4,728,823	332,445	(1,807,151)	3,254,117
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	5,857,645	939,304	-	6,796,949
Accumulated deferred investment tax credits	321,276	-	-	321,276
Obligations under capital leases	294,257	-	-	294,257
Other regulatory liabilities	284,239	-	-	284,239
Decommissioning and retirement cost liabilities	1,465,242	1,251,844	-	2,717,086
Accumulated provisions	131,395	8,317	-	139,712
Pension and other postretirement liabilities	1,730,536	426,249	-	2,156,785
Long-term debt	10,746,346	180,477	(5,388)	10,921,435
Other	566,500	774,071	(555,277)	785,294
TOTAL	21,397,436	3,580,262	(560,665)	24,417,033
EQUITY
Shareholders' Equity:
Common stock, $.01 par value, authorized 500,000,000 shares;
issued 254,772,087 shares in 2009	2,163,814	911,495	(3,072,761)	2,548
Paid-in capital	7,460,265	2,156,932	(4,246,751)	5,370,446
Retained earnings	5,380,457	1,814,044	289,454	7,483,955
Accumulated other comprehensive income (loss)	(118,975)	58,257	626	(60,092)
Less - treasury stock, at cost (58,693,564 shares in 2009)	4,286,451	12,700	(132,700)	4,166,451
Total shareholders' equity	10,599,110	4,928,028	(6,896,732)	8,630,406
Subsidiaries' preferred stock without sinking fund	280,510	82,283	(51,762)	311,031
TOTAL	10,879,620	5,010,311	(6,948,494)	8,941,437
TOTAL LIABILITIES AND EQUITY	$ 37,005,879	$ 8,923,018	$ (9,316,310)	$ 36,612,587
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Balance Sheet
December 31, 2008
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other	Competitive Businesses	Eliminations	Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents:
Cash	$ 110,203	$ 5,673	$ -	$ 115,876
Temporary cash investments	1,355,498	449,117	-	1,804,615
Total cash and cash equivalents	1,465,701	454,790	-	1,920,491
Securitization recovery trust account	12,062	-	-	12,062
Notes receivable	99,330	1,333,123	(1,432,453)	-
Accounts receivable:
Customer	523,348	210,856	-	734,204
Allowance for doubtful accounts	(25,610)	-	-	(25,610)
Associated companies	139,912	84,341	(224,253)	-
Other	179,207	27,420	-	206,627
Accrued unbilled revenues	282,914	-	-	282,914
Total accounts receivable	1,099,771	322,617	(224,253)	1,198,135
Deferred fuel costs	167,092	-	-	167,092
Accumulated deferred income taxes	7,307	-	-	7,307
Fuel inventory - at average cost	213,313	2,832	-	216,145
Materials and supplies - at average cost	505,720	270,450	-	776,170
Deferred nuclear refueling outage costs	106,514	115,289	-	221,803
System agreement cost equalization	394,000	-	-	394,000
Prepayments and other	106,044	144,200	(3,060)	247,184
TOTAL	4,176,854	2,643,301	(1,659,766)	5,160,389
OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity	7,354,792	(296,465)	(6,992,080)	66,247
Decommissioning trust funds	1,143,391	1,688,852	-	2,832,243
Non-utility property - at cost (less accumulated depreciation)	226,333	4,782	-	231,115
Other	103,308	10,019	(5,388)	107,939
TOTAL	8,827,824	1,407,188	(6,997,468)	3,237,544
PROPERTY, PLANT, AND EQUIPMENT
Electric	30,878,491	3,616,915	-	34,495,406
Property under capital lease	745,504	-	-	745,504
Natural gas	303,769	-	-	303,769
Construction work in progress	1,458,181	254,580	-	1,712,761
Nuclear fuel under capital lease	465,374	-	-	465,374
Nuclear fuel	130,675	506,138	-	636,813
TOTAL PROPERTY, PLANT AND EQUIPMENT	33,981,994	4,377,633	-	38,359,627
Less - accumulated depreciation and amortization	15,365,659	564,854	-	15,930,513
PROPERTY, PLANT AND EQUIPMENT - NET	18,616,335	3,812,779	-	22,429,114
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
SFAS 109 regulatory asset - net	581,719	-	-	581,719
Other regulatory assets	3,615,104	-	-	3,615,104
Deferred fuel costs	168,122	-	-	168,122
Goodwill	374,099	3,073	-	377,172
Other	744,499	868,454	(565,299)	1,047,654
TOTAL	5,483,543	871,527	(565,299)	5,789,771
TOTAL ASSETS	$ 37,104,556	$ 8,734,795	$ (9,222,533)	$ 36,616,818
*Totals may not foot due to rounding.
Entergy Corporation
Consolidating Balance Sheet
December 31, 2008
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other	Competitive Businesses	Eliminations	Consolidated
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Currently maturing long-term debt	$ 514,911	$ 29,549	$ -	$ 544,460
Notes payable:
Associated companies	1,341,198	91,255	(1,432,453)	-
Other	55,034	-	-	55,034
Account payable:
Associated companies	97,530	126,413	(223,943)	-
Other	1,222,415	253,330	-	1,475,745
Customer deposits	302,303	-	-	302,303
Taxes accrued	175,920	(100,710)	-	75,210
Interest accrued	185,778	1,532	-	187,310
Deferred fuel costs	183,539	-	-	183,539
Obligations under capital leases	162,393	-	-	162,393
Pension and other postretirement liabilities	41,653	4,635	-	46,288
System agreement cost equalization	460,315	-	-	460,315
Other	146,808	129,549	(3,060)	273,297
TOTAL	4,889,797	535,553	(1,659,456)	3,765,894
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	5,718,488	847,282	-	6,565,770
Accumulated deferred investment tax credits	325,570	-	-	325,570
Obligations under capital leases	343,093	-	-	343,093
Other regulatory liabilities	280,643	-	-	280,643
Decommissioning and retirement cost liabilities	1,447,659	1,229,836	-	2,677,495
Accumulated provisions	136,449	11,003	-	147,452
Pension and other postretirement liabilities	1,731,824	446,169	-	2,177,993
Long-term debt	10,991,204	188,473	(5,388)	11,174,289
Other	735,252	720,223	(574,477)	880,998
TOTAL	21,710,182	3,442,986	(579,865)	24,573,303
EQUITY
Shareholders' Equity:
Common stock, $.01 par value, authorized 500,000,000 shares;
issued 248,174,087 shares in 2008	2,163,749	911,494	(3,072,761)	2,482
Paid-in capital	6,979,623	2,138,165	(4,248,485)	4,869,303
Retained earnings	5,494,812	1,631,437	256,470	7,382,719
Accumulated other comprehensive income (loss)	(118,904)	5,580	626	(112,698)
Less - treasury stock, at cost (58,815,518 shares in 2008)	4,295,214	12,700	(132,700)	4,175,214
Total shareholders' equity	10,224,066	4,673,976	(6,931,450)	7,966,592
Subsidiaries' preferred stock without sinking fund	280,511	82,280	(51,762)	311,029
TOTAL	10,504,577	4,756,256	(6,983,212)	8,277,621
TOTAL LIABILITIES AND EQUITY	$ 37,104,556	$ 8,734,795	$ (9,222,533)	$ 36,616,818
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Balance Sheet
March 31, 2009 vs December 31, 2008
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other	Competitive Businesses	Eliminations	Consolidated
ASSETS
CURRENT ASSETS
Cash and cash equivalents:
Cash	$ (20,297)	$ (1,207)	$ -	$ (21,504)
Temporary cash investments	(139,479)	43,450	-	(96,029)
Total cash and cash equivalents	(159,776)	42,243	-	(117,533)
Securitization recovery trust account	7,831	-	-	7,831
Notes receivable	(93,878)	3,250	90,628	-
Accounts receivable:
Customer	(81,727)	(35,345)	-	(117,072)
Allowance for doubtful accounts	(249)	-	-	(249)
Associated companies	198,717	7,602	(206,319)	-
Other	(39,646)	(11,952)	-	(51,598)
Accrued unbilled revenues	(34,231)	-	-	(34,231)
Total accounts receivable	42,864	(39,695)	(206,319)	(203,150)
Deferred fuel costs	(147,565)	-	-	(147,565)
Accumulated deferred income taxes	28,925	-	-	28,925
Fuel inventory - at average cost	17,127	504	-	17,631
Materials and supplies - at average cost	(373)	6,482	-	6,109
Deferred nuclear refueling outage costs	(24,014)	21,447	-	(2,567)
System agreement cost equalization	-	-	-	-
Prepayments and other	57,020	112,143	(53,867)	115,296
TOTAL	(271,839)	146,374	(169,558)	(295,023)
OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity	(33,082)	(2,558)	33,017	(2,623)
Decommissioning trust funds	(48,865)	(64,689)	-	(113,554)
Non-utility property - at cost (less accumulated depreciation)	96	(645)	-	(549)
Other	2,137	814	-	2,951
TOTAL	(79,714)	(67,078)	33,017	(113,775)
PROPERTY, PLANT, AND EQUIPMENT
Electric	668,364	18,623	-	686,987
Property under capital lease	(352)	-	-	(352)
Natural gas	3,085	-	-	3,085
Construction work in progress	(224,469)	72,938	-	(151,531)
Nuclear fuel under capital lease	(48,461)	-	-	(48,461)
Nuclear fuel	30,354	5,133	-	35,487
TOTAL PROPERTY, PLANT AND EQUIPMENT	428,521	96,694	-	525,215
Less - accumulated depreciation and amortization	300,743	33,909	-	334,652
PROPERTY, PLANT AND EQUIPMENT - NET	127,778	62,785	-	190,563
DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
SFAS 109 regulatory asset - net	25,987	-	-	25,987
Other regulatory assets	88,228	-	-	88,228
Deferred fuel costs	-	-	-	-
Goodwill	-	-	-	-
Other	10,883	46,142	42,764	99,789
TOTAL	125,098	46,142	42,764	214,004
TOTAL ASSETS	$ (98,677)	$ 188,223	$ (93,777)	$ (4,231)
*Totals may not foot due to rounding.
Entergy Corporation
Consolidating Balance Sheet
March 31, 2009 vs December 31, 2008
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other	Competitive Businesses	Eliminations	Consolidated
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Currently maturing long-term debt	$ 30,600	$ 587	$ -	$ 31,187
Notes payable:
Associated companies	(16,988)	(73,640)	90,628	-
Other	25,000	-	-	25,000
Account payable:
Associated companies	301,395	(118,639)	(182,756)	-
Other	(559,825)	(41,852)	-	(601,677)
Customer deposits	7,730	-	-	7,730
Taxes accrued	(47,096)	34,312	-	(12,784)
Interest accrued	(37,979)	565	-	(37,414)
Deferred fuel costs	127,943	-	-	127,943
Obligations under capital leases	22	-	-	22
Pension and other postretirement liabilities	(8,058)	108	-	(7,950)
System agreement cost equalization	-	-	-	-
Other	16,282	(4,549)	(55,567)	(43,834)
TOTAL	(160,974)	(203,108)	(147,695)	(511,777)
NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	139,157	92,022	-	231,179
Accumulated deferred investment tax credits	(4,294)	-	-	(4,294)
Obligations under capital leases	(48,836)	-	-	(48,836)
Other regulatory liabilities	3,596	-	-	3,596
Decommissioning and retirement cost liabilities	17,583	22,008	-	39,591
Accumulated provisions	(5,054)	(2,686)	-	(7,740)
Pension and other postretirement liabilities	(1,288)	(19,920)	-	(21,208)
Long-term debt	(244,858)	(7,996)	-	(252,854)
Other	(168,752)	53,848	19,200	(95,704)
TOTAL	(312,746)	137,276	19,200	(156,270)
EQUITY
Shareholders' Equity:
Common stock, $.01 par value, authorized 500,000,000 shares;
issued 254,772,087 shares in 2009 and 248,174,087 shares in 2008	65	1	-	66
Paid-in capital	480,642	18,767	1,734	501,143
Retained earnings	(114,355)	182,607	32,984	101,236
Accumulated other comprehensive income (loss)	(71)	52,677	-	52,606
Less - treasury stock, at cost	(8,763)	-	-	(8,763)
Total shareholders' equity	375,044	254,052	34,718	663,814
Subsidiaries' preferred stock without sinking fund	(1)	3	-	2
TOTAL	375,043	254,055	34,718	663,816
TOTAL LIABILITIES AND EQUITY	$ (98,677)	$ 188,223	$ (93,777)	$ (4,231)
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Three Months Ended March 31, 2009
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other	Competitive Businesses	Eliminations	Consolidated
OPERATING REVENUES
Electric	$ 2,028,156	$ -	$ (1,240)	$ 2,026,916
Natural gas	74,049	-	-	74,049
Competitive businesses	6,323	687,606	(5,782)	688,147
Total	2,108,528	687,606	(7,022)	2,789,112
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale	778,401	67,931	-	846,332
Purchased power	316,532	13,112	(6,389)	323,255
Nuclear refueling outage expenses	25,090	31,689	-	56,779
Other operation and maintenance	436,106	209,343	(747)	644,702
Decommissioning	25,037	23,705	-	48,742
Taxes other than income taxes	107,548	26,849	-	134,397
Depreciation and amortization	222,319	35,533	-	257,852
Other regulatory charges (credits) - net	(29,474)	-	-	(29,474)
Total	1,881,559	408,162	(7,136)	2,282,585
OPERATING INCOME	226,969	279,444	114	506,527
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	16,947	-	-	16,947
Interest and dividend income	39,111	24,681	(33,142)	30,650
Equity in earnings (loss) of unconsolidated equity affiliates	(52)	(3,075)	-	(3,127)
Miscellaneous - net	(5,083)	(4,975)	(114)	(10,172)
Total	50,923	16,631	(33,256)	34,298
INTEREST AND OTHER CHARGES
Interest on long-term debt	125,840	2,125	-	127,965
Other interest - net	40,706	11,729	(33,142)	19,293
Allowance for borrowed funds used during construction	(9,812)	-	-	(9,812)
Total	156,734	13,854	(33,142)	137,446
INCOME BEFORE INCOME TAXES	121,158	282,221	-	403,379
Income taxes	56,788	106,258	-	163,046
CONSOLIDATED NET INCOME	64,370	175,963	-	240,333
Preferred dividend requirements of subsidiaries	4,333	665	-	4,998
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$ 60,037	$ 175,298	$ -	$ 235,335
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$0.31	$0.91		$1.22
DILUTED	$0.32	$0.88		$1.20
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC				192,593,601
DILUTED				198,058,002
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Three Months Ended March 31, 2008
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other	Competitive Businesses	Eliminations	Consolidated
OPERATING REVENUES
Electric	$ 2,046,935	$ -	$ (708)	$ 2,046,227
Natural gas	89,395	-	-	89,395
Competitive businesses	6,007	729,278	(6,173)	729,112
Total	2,142,337	729,278	(6,881)	2,864,734
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale	454,583	85,918	-	540,501
Purchased power	611,851	15,412	(6,622)	620,642
Nuclear refueling outage expenses	19,337	31,922	-	51,258
Other operation and maintenance	419,934	191,707	(373)	611,268
Decommissioning	23,325	22,671	-	45,996
Taxes other than income taxes	85,786	22,785	-	108,571
Depreciation and amortization	212,423	32,562	-	244,985
Other regulatory charges (credits) - net	35,280	-	-	35,280
Total	1,862,519	402,977	(6,995)	2,258,501
OPERATING INCOME	279,818	326,301	114	606,233
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	9,286	-	-	9,286
Interest and dividend income	43,322	37,495	(26,535)	54,282
Equity in earnings (loss) of unconsolidated equity affiliates	485	(1,414)	-	(929)
Miscellaneous - net	(6,047)	(5,395)	(114)	(11,556)
Total	47,046	30,686	(26,649)	51,083
INTEREST AND OTHER CHARGES
Interest on long-term debt	123,071	73	-	123,144
Other interest - net	40,754	18,319	(26,535)	32,538
Allowance for borrowed funds used during construction	(5,116)	-	-	(5,116)
Total	158,709	18,392	(26,535)	150,566
INCOME BEFORE INCOME TAXES	168,155	338,595	-	506,750
Income taxes	68,527	124,476	-	193,003
CONSOLIDATED NET INCOME	99,628	214,119	-	313,747
Preferred dividend requirements of subsidiaries	4,332	665	-	4,998
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$ 95,296	$ 213,454	$ -	$ 308,749
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$0.49	$1.11		$1.60
DILUTED	$0.48	$1.08		$1.56
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC				192,639,605
DILUTED				198,300,041
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Three Months Ended March 31, 2009 vs. 2008
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other	Competitive Businesses	Eliminations	Consolidated
OPERATING REVENUES
Electric	$ (18,779)	$ -	$ (532)	$ (19,311)
Natural gas	(15,346)	-	-	(15,346)
Competitive businesses	316	(41,672)	391	(40,965)
Total	(33,809)	(41,672)	(141)	(75,622)
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale	323,818	(17,987)	-	305,831
Purchased power	(295,319)	(2,300)	233	(297,387)
Nuclear refueling outage expenses	5,753	(233)	-	5,521
Other operation and maintenance	16,172	17,636	(374)	33,434
Decommissioning	1,712	1,034	-	2,746
Taxes other than income taxes	21,762	4,064	-	25,826
Depreciation and amortization	9,896	2,971	-	12,867
Other regulatory charges (credits )- net	(64,754)	-	-	(64,754)
Total	19,040	5,185	(141)	24,084
OPERATING INCOME	(52,849)	(46,857)	-	(99,706)
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	7,661	-	-	7,661
Interest and dividend income	(4,211)	(12,814)	(6,607)	(23,632)
Equity in earnings (loss) of unconsolidated equity affiliates	(537)	(1,661)	-	(2,198)
Miscellaneous - net	964	420	-	1,384
Total	3,877	(14,055)	(6,607)	(16,785)
INTEREST AND OTHER CHARGES
Interest on long-term debt	2,769	2,052	-	4,821
Other interest - net	(48)	(6,590)	(6,607)	(13,245)
Allowance for borrowed funds used during construction	(4,696)	-	-	(4,696)
Total	(1,975)	(4,538)	(6,607)	(13,120)
INCOME BEFORE INCOME TAXES	(46,997)	(56,374)	-	(103,371)
Income taxes	(11,739)	(18,218)	-	(29,957)
CONSOLIDATED NET INCOME	(35,258)	(38,156)	-	(73,414)
Preferred dividend requirements of subsidiaries	-	-	-	-
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$ (35,258)	$ (38,156)	$ -	$ (73,414)
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	($0.18)	($0.20)		($0.38)
DILUTED	($0.16)	($0.20)		($0.36)
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Twelve Months Ended March 31, 2009
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other	Competitive Businesses	Eliminations	Consolidated
OPERATING REVENUES
Electric	$ 10,057,996	$ -	$ (4,147)	$ 10,053,849
Natural gas	226,511	-	-	226,511
Competitive businesses	29,327	2,729,410	(20,962)	2,737,775
Total	10,313,834	2,729,410	(25,109)	13,018,135
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale	3,536,222	347,373	-	3,883,595
Purchased power	2,162,423	54,707	(23,317)	2,193,813
Nuclear refueling outage expenses	97,974	129,305	-	227,279
Other operation and maintenance	1,945,953	832,492	(2,248)	2,776,197
Decommissioning	97,533	94,623	-	192,156
Taxes other than income taxes	427,439	95,340	-	522,779
Depreciation and amortization	906,528	137,199	-	1,043,727
Other regulatory charges (credits) - net	(4,871)	-	-	(4,871)
Total	9,169,201	1,691,039	(25,565)	10,834,675
OPERATING INCOME	1,144,633	1,038,371	456	2,183,460
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	52,183	-	-	52,183
Interest and dividend income	152,083	92,219	(119,715)	124,587
Equity in earnings (loss) of unconsolidated equity affiliates	(2,698)	(11,184)	-	(13,882)
Miscellaneous - net	(13,083)	3,156	(456)	(10,383)
Total	188,485	84,191	(120,171)	152,505
INTEREST AND OTHER CHARGES
Interest on long-term debt	502,450	3,270	-	505,720
Other interest - net	176,327	63,434	(119,715)	120,046
Allowance for borrowed funds used during construction	(29,962)	-	-	(29,962)
Total	648,815	66,704	(119,715)	595,804
INCOME BEFORE INCOME TAXES	684,303	1,055,858	-	1,740,161
Income taxes	280,255	292,785	-	573,040
CONSOLIDATED NET INCOME	404,048	763,073	-	1,167,121
Preferred dividend requirements of subsidiaries	17,307	2,662	-	19,969
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$ 386,741	$ 760,411	$ -	$ 1,147,152
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$2.03	$4.00		$6.03
DILUTED	$2.05	$3.82		$5.87
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC				190,387,963
DILUTED				199,282,466
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Twelve Months Ended March 31, 2008
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other	Competitive Businesses	Eliminations	Consolidated
OPERATING REVENUES
Electric	$ 8,983,790	$ -	$ (2,721)	$ 8,981,069
Natural gas	210,516	-	-	210,516
Competitive businesses	28,870	2,457,998	(23,380)	2,463,488
Total	9,223,176	2,457,998	(26,101)	11,655,073
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale	2,360,741	327,182	-	2,687,923
Purchased power	2,121,746	66,847	(25,239)	2,163,354
Nuclear refueling outage expenses	75,022	114,233	-	189,255
Other operation and maintenance	1,860,522	837,341	(1,318)	2,696,545
Decommissioning	90,832	85,232	-	176,064
Taxes other than income taxes	389,367	85,580	-	474,947
Depreciation and amortization	855,664	120,622	-	976,286
Other regulatory charges (credits) - net	66,694	-	-	66,694
Total	7,820,588	1,637,037	(26,557)	9,431,068
OPERATING INCOME	1,402,588	820,961	456	2,224,005
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	34,770	-	-	34,770
Interest and dividend income	175,114	144,532	(88,477)	231,169
Equity in earnings (loss) of unconsolidated equity affiliates	1,112	(488)	-	624
Miscellaneous - net	(13,213)	(17,428)	(456)	(31,097)
Total	197,783	126,616	(88,933)	235,466
INTEREST AND OTHER CHARGES
Interest on long-term debt	502,281	3,853	-	506,134
Other interest - net	186,317	58,491	(88,491)	156,317
Allowance for borrowed funds used during construction	(19,619)	-	-	(19,619)
Total	668,979	62,344	(88,491)	642,832
INCOME BEFORE INCOME TAXES	931,392	885,233	14	1,816,639
Income taxes	364,044	197,310	-	561,354
CONSOLIDATED NET INCOME	567,348	687,923	14	1,255,285
Preferred dividend requirements of subsidiaries	20,651	3,217	14	23,882
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$ 546,697	$ 684,706	$ -	$ 1,231,403
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	$2.81	$3.52		$6.33
DILUTED	$2.73	$3.41		$6.14
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC				194,617,035
DILUTED				200,714,460
*Totals may not foot due to rounding.

Entergy Corporation
Consolidating Income Statement
Twelve Months Ended March 31, 2009 vs. 2008
(Dollars in thousands)
(Unaudited)
	U.S. Utilities/ Parent & Other	Competitive Businesses	Eliminations	Consolidated
OPERATING REVENUES
Electric	$ 1,074,206	$ -	$ (1,426)	$ 1,072,780
Natural gas	15,995	-	-	15,995
Competitive businesses	457	271,412	2,418	274,287
Total	1,090,658	271,412	992	1,363,062
OPERATING EXPENSES
Operating and Maintenance:
Fuel, fuel related expenses, and gas purchased for resale	1,175,481	20,191	-	1,195,672
Purchased power	40,677	(12,140)	1,922	30,459
Nuclear refueling outage expenses	22,952	15,072	-	38,024
Other operation and maintenance	85,431	(4,849)	(930)	79,652
Decommissioning	6,701	9,391	-	16,092
Taxes other than income taxes	38,072	9,760	-	47,832
Depreciation and amortization	50,864	16,577	-	67,441
Other regulatory charges (credits )- net	(71,565)	-	-	(71,565)
Total	1,348,613	54,002	992	1,403,607
OPERATING INCOME	(257,955)	217,410	-	(40,545)
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	17,413	-	-	17,413
Interest and dividend income	(23,031)	(52,313)	(31,238)	(106,582)
Equity in earnings (loss) of unconsolidated equity affiliates	(3,810)	(10,696)	-	(14,506)
Miscellaneous - net	130	20,584	-	20,714
Total	(9,298)	(42,425)	(31,238)	(82,961)
INTEREST AND OTHER CHARGES
Interest on long-term debt	169	(583)	-	(414)
Other interest - net	(9,990)	4,943	(31,224)	(36,271)
Allowance for borrowed funds used during construction	(10,343)	-	-	(10,343)
Total	(20,164)	4,360	(31,224)	(47,028)
INCOME BEFORE INCOME TAXES	(247,089)	170,625	(14)	(76,478)
Income taxes	(83,789)	95,475	-	11,686
CONSOLIDATED NET INCOME	(163,300)	75,150	(14)	(88,164)
Preferred dividend requirements of subsidiaries	(3,344)	(555)	(14)	(3,913)
NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION	$ (159,956)	$ 75,705	$ -	$ (84,251)
EARNINGS PER AVERAGE COMMON SHARE:
BASIC	($0.78)	$0.48		($0.30)
DILUTED	($0.68)	$0.41		($0.27)
*Totals may not foot due to rounding.

Entergy Corporation
Consolidated Cash Flow Statement
Three Months Ended March 31, 2009 vs. 2008
(Dollars in thousands)
(Unaudited)
	2009	2008	Variance
OPERATING ACTIVITIES
Consolidated net income	$240,333	$313,747	($73,414)
Adjustments to reconcile consolidated net income to net cash flow
provided by operating activities:
Reserve for regulatory adjustments	1,210	(2,909)	4,119
Other regulatory charges (credits) - net	(29,474)	35,280	(64,754)
Depreciation, amortization, and decommissioning	306,595	290,981	15,614
Deferred income taxes, investment tax credits, and non-current taxes accrued	155,029	97,984	57,045
Equity in earnings of unconsolidated equity affiliates - net of dividends	3,127	929	2,198
Changes in working capital:
Receivables	102,428	(9,374)	111,802
Fuel inventory	(17,631)	(22,665)	5,034
Accounts payable	(134,008)	9,522	(143,530)
Taxes accrued	(12,784)	-	(12,784)
Interest accrued	(37,413)	(34,238)	(3,175)
Deferred fuel	275,508	(195,650)	471,158
Other working capital accounts	(120,505)	(181,401)	60,896
Provision for estimated losses and reserves	1,281	4,034	(2,753)
Changes in other regulatory assets	(447,882)	40,569	(488,451)
Other	88,805	101,361	(12,556)
Net cash flow provided by operating activities	374,619	448,170	(73,551)
INVESTING ACTIVITIES
Construction/capital expenditures	(455,737)	(373,317)	(82,420)
Allowance for equity funds used during construction	16,947	9,286	7,661
Nuclear fuel purchases	(118,890)	(170,381)	51,491
Proceeds from sale/leaseback of nuclear fuel	11,040	112,700	(101,660)
Payment for purchase of plant	-	(56,409)	56,409
Changes in transition charge account	(7,831)	(8,352)	521
NYPA value sharing payment	(72,000)	(72,000)	-
Decrease (increase) in other investments	7,339	7,974	(635)
Proceeds from nuclear decommissioning trust fund sales	583,166	257,718	325,448
Investment in nuclear decommissioning trust funds	(610,836)	(294,840)	(315,996)
Net cash flow used in investing activities	(646,802)	(587,621)	(59,181)
FINANCING ACTIVITIES
Proceeds from the issuance of:
Long-term debt	489,987	545,000	(55,013)
Common stock and treasury stock	927	4,670	(3,743)
Retirement of long-term debt	(215,023)	(438,227)	223,204
Repurchase of common stock	-	(158,182)	158,182
Changes in credit line borrowings - net	25,000	-	25,000
Dividends paid:
Common stock	(142,085)	(144,579)	2,494
Preferred stock	(4,998)	(7,270)	2,272
Net cash flow provided by (used in) financing activities	153,808	(198,588)	352,396
Effect of exchange rates on cash and cash equivalents	842	17	825
Net increase (decrease) in cash and cash equivalents	(117,533)	(338,022)	220,489
Cash and cash equivalents at beginning of period	1,920,491	1,253,728	666,763
Cash and cash equivalents at end of period	$1,802,958	$915,706	$887,252
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized	$176,892	$183,787	($6,895)
Income taxes	($15,139)	$2,157	($17,296)
Noncash financing activities:
Long-term debt retired (equity unit notes)	($500,000)	-	($500,000)
Common stock issued in settlement of equity unit purchase contracts	$500,000	-	$500,000

Entergy Corporation
Consolidated Cash Flow Statement
Twelve Months Ended March 31, 2009 vs. 2008
(Dollars in thousands)
(Unaudited)
	2009	2008	Variance
OPERATING ACTIVITIES
Consolidated net income	$1,167,121	$1,255,285	($88,164)
Adjustments to reconcile consolidated net income to net cash flow
provided by operating activities:
Reserve for regulatory adjustments	(4,166)	(29,422)	25,256
Other regulatory charges (credits) - net	(4,871)	66,694	(71,565)
Depreciation, amortization, and decommissioning	1,235,883	1,152,351	83,532
Deferred income taxes, investment tax credits, and non-current taxes accrued	390,993	189,901	201,092
Equity in earnings (loss) of unconsolidated equity affiliates - net of dividends	13,882	(624)	14,506
Changes in working capital:
Receivables	190,455	(138,162)	328,617
Fuel inventory	(2,527)	(33,304)	30,777
Accounts payable	(166,755)	188,721	(355,476)
Taxes accrued	62,426	2,087	60,339
Interest accrued	(3,827)	(249)	(3,578)
Deferred fuel	432,658	(348,798)	781,456
Other working capital accounts	(11,476)	(147,590)	136,114
Provision for estimated losses and reserves	9,709	(38,656)	48,365
Changes in other regulatory assets	(812,662)	126,519	(939,181)
Changes in pensions and other postretirement liabilities	816,713	(94,070)	910,783
Other	(62,779)	363,939	(426,718)
Net cash flow provided by operating activities	3,250,777	2,514,622	736,155
INVESTING ACTIVITIES
Construction/capital expenditures	(2,294,675)	(1,648,780)	(645,895)
Allowance for equity funds used during construction	52,184	34,770	17,414
Nuclear fuel purchases	(372,460)	(394,307)	21,847
Proceeds from sale/leaseback of nuclear fuel	195,437	167,280	28,157
Proceeds from sale of assets and businesses	30,725	400	30,325
Payment for purchase of plant	(210,414)	(392,620)	182,206
Changes in transition charge account	7,732	(27,625)	35,357
NYPA value sharing payment	(72,000)	(72,000)	-
Insurance proceeds received for property damages	130,114	83,104	47,010
Decrease (increase) in other investments	(73,468)	(56,229)	(17,239)
Proceeds from nuclear decommissioning trust fund sales	1,977,725	1,681,295	296,430
Investment in nuclear decommissioning trust funds	(2,020,177)	(1,814,068)	(206,109)
Net cash flow used in investing activities	(2,649,277)	(2,438,780)	(210,497)
FINANCING ACTIVITIES
Proceeds from the issuance of:
Long-term debt	3,401,682	2,591,138	810,544
Preferred stock	-	10,000	(10,000)
Common stock and treasury stock	31,032	52,611	(21,579)
Retirement of long-term debt	(2,263,602)	(1,473,299)	(790,303)
Repurchase of common stock	(354,169)	(815,574)	461,405
Redemption of preferred stock	-	(55,577)	55,577
Changes in credit line borrowings - net	55,000	-	55,000
Dividends paid:
Common stock	(570,551)	(542,939)	(27,612)
Preferred stock	(17,753)	(27,066)	9,313
Net cash flow provided by (used in) financing activities	281,639	(260,706)	542,345
Effect of exchange rates on cash and cash equivalents	4,113	58	4,055
Net increase (decrease) in cash and cash equivalents	887,252	(184,806)	1,072,058
Cash and cash equivalents at beginning of period	915,706	1,100,512	(184,806)
Cash and cash equivalents at end of period	$1,802,958	$915,706	$887,252
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized	$605,393	$641,071	($35,678)
Income taxes	$119,938	$347,532	($227,594)
Noncash investing and financing activities:
Long-term debt retired (equity unit notes)	($500,000)	-	($500,000)
Common stock issued in settlement of equity unit purchase contracts	$500,000	-	$500,000